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B  E  R  K  E  L  8  Y^ 

LIBRARY 


UNIVWSITY  OF 
CALIFORNIA 


y 


EARTH 

SCIENCW 

UBRARV 


S.     J-H-f^^^'^l     t^e^C-^  ^hUic-ip 


MANUAL 

FOR  THE 

OIL  AND  GAS  INDUSTRY 

UNDER  THE 

REVENUE  ACT  OF  1918 


BY 

RALPH  ARNOLD,  J.  L.  DARNELL 

and  Others 


NEW  YORK 
JOHN    WILEY   &   SONS,    Inc. 

London:  CHAPMAN  &  HALL,  Limited 
1920 


This  monograph  is  reprinted  with  the  permission  of  the 

Oil  and  Gas  Section,  Internal  Revenue  Bureau 

which  issued  it  as  a  Bulletin. 


Cat.  ^Qp 


PRE<;S   OF 

BRAUNWORTH  &  CO. 

BOOK  MANUFACTURERS 

BROOKLYN  N.  V 


FOREWORD 


This  manual  is  issued  to  assist  the  taxpayer  of  the  oil  and  gas 
industry  in  correctly  and  expeditiously  preparing  his  Federal  tax 
returns.  Although  the  endeavor  has  been  to  anticipate  all  ques- 
tions that  might  be  asked  regarding  the  law  and  regulations,  and 
the  latter  have  been  amplified  when  it  was  deemed  necessary  to 
secure  the  desired  result,  it  is  recognized  that  any  such  manual  is 
merely  suggestive  and  can  not  cover  all  situations  which  may  exist. 

The  book  consists  of  three  parts. 

Part  I  deals  directly  with  the  law  and  regulations  as  they  relate 
to  the  oil  and  gas  industry. 

Part  II,  dealing  with  the  question  of  depreciation,  is  included 
to  assist  the  taxpayer  in  standardizing  his  classification  of  equip- 
ment and  to  offer  a  suggestion  as  to  relative  rates  of  depreciation 
for  different  types  of  physical  property.  The  rates  are  not  to  be 
applied  indiscriminately  to  specific  cases,  and  the  Treasury  De- 
partment is  in  no  way  committed  to  accept  them  in  the  returns. 

Part  III  consists  of  descriptions  of  methods  of  estimating  under- 
ground oil  reserves,  especially  by  means  of  production  curves,  and 
a  collection  of  curves  and  tables  covering  many  of  the  principal 
oil  pools  and  fields  in  the  United  States.  The  curves  and  tables  are 
intended  as  a  suggestio7i  for  the  guidance  of  the  taxpayer  in  the 
computation  of  his  depletion  allowance,  which  in  turn  usually  has 
a  direct  bearing  on  the  amount  of  his  tax.  They  are  not  to  be 
applied  indiscriminately  to  specific  properties,  and  the  Treasury 
Department  is  in  no  way  committed  to  accept  estimates  based 
upon  them.  Every  claim  for  deduction  on  account  of  depletion 
must  be  accompanied  by  a  detailed  statement  of  production,  etc., 
upon  which  such  claim  is  based. 

These  curves  and  tables  are  based  upon  a  careful  systematic 
study  of  thousands  of  production  records;  all  that  could  be  made 
available  in  the  limited  time  at  the  disposal  of  the  Bureau.     Many 


01441 


iv  FOREWORD 

refinements  and  minor  corrections  are  desirable  but  must  be 
delaj^ed  until  more  complete  records  are  in  hand.  With  such 
records  it  will  be  possible  to  make  curves  to  apply  to  more  restricted 
areas  and  thus  more  closely  approximate  the  conditions  which 
apply  to  individual  tracts. 

Usually  it  will  be  to  the  advantage  of  the  producer  to  make 
estimates  for  each  property  rather  than  to  assume  that  his  par- 
ticular property  is  an  average.  Any  or  all  of  the  methods  dis- 
cussed may  be  applied  by  the  producer  to  his  own  properties. 
Obviously,  manner  of  operation,  accidents,  and  other  factors  will 
influence  the  future  production  just  as  they  have  the  past  produc- 
tion, but  experience  has  shown  that  ordmarily  these  are  not  likely 
to  cause  wide  deviation  from  estimates  which  have  been  carefully 
made.  Examination  of  production  records  of  individual  proper- 
ties will  show  whether  the  probability  of  such  occurrences  will 
make  estimates  unsafe. 

In  cases  of  apparent  hardship  to  the  taxpayer  it  will  not  infre- 
quently happen  that  such  hardships  are  the  direct  result  of  failure 
on  his  part  to  procure  sufficiently  detailed  records,  and,  lacking 
these,  great  difficulty  will  be  encountered  in  establishing  the  facts. 
Such  conditions  may  have  been  excusable  in  the  past,  but  hence- 
forth the  responsibility  rests  squarely  upon  the  taxpayer,  as  his 
claims  must  be  supported  by  all  necessary  data  bearing  on  the  case. 

The  investigation  resulting  in  the  preparation  of  this  manual 
w^as  begun  before  the  signing  of  the  armistice,  and  most  of  the  men 
who  took  part  in  it  were  called  from  their  usual  vocations  and  under- 
took the  work  at  a  financial  sacrifice,  and  often  at  great  personal 
inconvenience.  The  oil  operators  throughout  the  country  have 
been  most  generous  in  their  cooperation  in  the  prosecution  of  the 
work,  not  only  as  individuals  but  in  their  organizations.  The 
hearty  support  of  the  Bureau  of  Mines,  Geological  Survey,  Fuel 
Administration,  and  other  Federal  bureaus  has  at  all  times  been 
given.  Without  the  assistance  of  these  agencies  the  work  could 
not  have  been  finished.  The  Bureau  is  therefore  greatly  indebted 
to  all  for  their  services,  and  wishes  to  extend  its  thanks  for  their 
assistance. 


CONTENTS 


PAOB 

Foreword iii 

Introduction xi 

PART  I 

AMPLIFICATION  OF  THE   LAW  AND   REGULATIONS. 

Kinds  of  taxes  imposed 1 

Limit  on  surtax  and  war-profits  and  excess-profits  tax  in  case  of  sale ....  3 

Gross  income  and  net  income 5 

Basis  for  deductions 5 

Invested  capital 5 

"Capital  sum"  includes  "invested  capital" 7 

Physical  property 9 

Cost  of  property 9 

Cost  of  development 9 

General  expense 10 

Repairs 10 

Improvements  and  betterments 10 

Compensation  for  personal  services 11 

Bonuses  to  employees 11 

Time  for  deduction  of  charges 11 

Taxes 12 

Losses 12 

Depreciation 13 

Definition 13 

Depreciation  allowance 13 

Depreciable  property 14 

Depreciation  of  intangible  property 14 

Capital  sum  returnable  through  depreciation  allowances 15 

Method  of  computing  dei)rcciation  allowances 15 

Modification  of  method  of  computing  depreciation 15 

Charging  olT  depreciation 16 

Closing  (leprociation  account  as  to  any  item 16 

Depreciation  of  imi)rovemcnts  in  the  case  of  oil  and  gas  wells 17 

Depletion  and  drcpeciation  of  oil  and  gas  wells  in  years  before  191G.  17 

Amortization 18 

V 


vi  CONTENTS 

PAGE 

Depletion  of  oil  and  gas  wells 18 

Capital  recoverable  through  depletion  allowance  in  case  of  an  owner.  20 

Capital  recoverable  through  depletion  allowances  in  the  case  of  lessee .  20 

Illustration 21 

Apportionment  of  deduction  between  lessor  and  lessee 22 

Determination  of  cost  of  deposits 23 

Determinat  ion  of  fair  market  value 23 

Ruling  regarding  valuation 25 

No  revaluation  of  property  permitted 25 

Determination  of  quantity  of  oil  in  ground 25 

Methods  of  estimating  recoverable  reserves 26 

Computation  of  allowance  for  depletion  of  oil  wells 27 

Computations  of  allowance  for  depletion  of  gas  wells 29 

Methods  of  computing  gas  depletion 30 

Details  of  production  or  the  performance  record  of  the  well  or  prop- 
erty    30 

Decline  in  open-flow  capacity 30 

Comparison  with  life  history  of  similar  wells  or  properties,  particularly 

those  now  exhausted  or  nearing  exhaustion 30 

Size  of  reservoir  and  pressure  of  gas  or  the  pore  space  method 30 

Other  indications  of  depletion 31 

Closed  pressure  method 31 

Unit  costs  as  applied  to  natural  gas 32 

Corrections  and  refinements  of  closed  pressure  method 32 

Method  of  gauging 34 

Apportionment  of  depletion  among  various  sands 34 

Season  for  testing  wells  for  closed  pressure 35 

Formula 36 

Gas  well  pressure  records  to  be  kept 37 

Computation  of  allowance  where  quantity  of  oil  or  gas  is  uncertain 38 

Computation  of  depletion  allowance  for  combined  holdings  of  oil  properties  38 
Computation  of  depletion  allowance  for  combined  holdings  of  gas  prop- 
erties    39 

Depletion  and  depreciation  accounts  on  books 39 

Distribution  from  depletion  or  depreciation  reserve 40 

Statement  to  be  attached  to  a  return  where  depletion  of  oil  or  gas  is 

claimed 41 

Revaluation  of  oil  or  gas  properties  discovered  since  March  1,  1913 43 

Extract  from  Regulations  45 43 

Charges  to  capital  and  to  expense  in  the  case  of  oil  and  gas  wells 46 

Depletion  for  past  years  not  allowed  by  department 47 

Appendix  to  Part  I 

I.  Schedule  for  ascertaining  cost  of  property  as  of  any  specified  date .  .  47 

II.  Schedule  for  the  valuation  of  property  as  of  any  specified  date.  ...  53 

III.  Schedule  for  i)roof  of  discovery 59 

IV.  Schedule  for  depiction 61 


CONTEXTS  Vli 

PAGE 

V.  Schedule  for  depreciation 62 

VI.  Schedule  for  the  proof  of  bona  fide  sale 62 

VII.  Schedule  for  computation  of  profit  or  loss  from  sale  of  capital  assets  ti4 
VIII.  Schedule  for  proving  that  the  principal  value  has  been  demon- 
strated by  prospecting  or  exploration  and  discovery  work  done  by 

the  taxpayer 65 

PART  II 

ESTIMATE  OF  DEPRECIATION  OF  EQUIPMENT  USED  IN  THE 

OIL  AND   GAS   INDUSTRY 

Preface  to  Part  III 67 

Class  A,  No.  1,  drilling  equipment 68 

Class  A,  No.  2,  well  equipment 68 

Class  A,  No.  3,  dehydrators 69 

Class  A,  No.  4,  tanks 69 

Class  A,  No.  5,  tools 70 

Class  A,  No.  6,  transportation  equipment 70 

Class  A,  No.  7,  water  plants 70 

Class  A,  No.  8,  electric  equipment 70 

Class  A,  No.  9,  machine  shop 71 

Class  A,  No.  10,  buildings 71 

Class  B,  pipe  lines 71 

Class  C,  tank  cars 72 

Class  C,  refineries 72 

Calculated  depreciation  for  whole  refinery 73 

(a)  Complete  refinery 73 

{h)  Skimming  i)lant 73 

Sales  or  marketing  equijjment 75 

Natural  gas  utility  companies 76 

Natural  gas  gasoline  plants 77 

Summary 78 

PART  III 

ESTIMATE  OF   RECOVERABLE   UNDERGROUND   RESERVES  OF 

OIL 

Preface 80 

Section  A.     Methods 83 

Section  B.     Average  future  production  curves  and  tables 92 

Appalachian  district 92 

Lima-Indiana  and  Illinois  districts 107 

Midcontinont  district 117 

North  Louisiana  district 130 

Rocky  Mountain  district 141 

California  district 146 

(julf  (toast  of  Texas  and  Louisiana 16r» 

Gulf  Coast  Oil  Fields 167 

Mexico  ar.d  other  foreign  countries 173 


ILLUSTRATIONS 


Fui.     1.  (.'iirvps  illu.strsitin^  methods St 

2.  r!iirvos  illii.stnitiiif>;  niethnds Sf) 

•i.  Curves  illiisl  rutins:  (hciIkkI-! 88 

-4.  Future  production  curves,  A|)])alaehi;m  iield 99 

o.  Future  production  curves,  Lima-Iiuliana  field 110 

G.  Future  production  curves,  Illinois-Indiana  field W.i 

7.  Future  production  curves,  Mid-continent  field I'il 

8.  Future  jn'oduction  curves,  Mid-coiiliiienl  field 128 

9.  Future  product  ion  curves,  northwest  Louisiana  Held  i:?S 

10.  Future  production  curves.  Rocky  Mountain  field 14)} 

11.  Future  production  curves,  Caliiornia  field 1")9 

12.  Future  production  curves,  Caliiornia  field 1<>2 

l;j.  Cas  decline  curves 17(i 

Future  production  curve,  Humble  field U)7 

Future  i)roduction  curves,  Humble  antl  Goose  Creek  fields 169 

Future  production  curve,  Saratoga  field 170 

Future  production  curves,  Saratoga  and  Edgerlev  fields 171 

I'^ilinc  pidduclioii  curves,  Bafson,   Fvangeline,  Sour   Lake  and 

\inlon  fields 172 


INTRODUCTION 


This  Manual  was  first  issued  by  the  Bureau  of  Internal  Rev- 
enue of  the  Treasury  Department  in  Februaiy,  1919,  shortly  after 
the  passage  of  the  Revenue  Act  of  1910.  The  original  edition  of 
10,000  copies  was  soon  exhausted,  and  the  demand  for  the  book 
has  become  so  great  that  the  present  private  reprint,  bringing 
certain  features  up  to  date,  has  been  decided  upon. 

The  volume  was  prepared  to  assist  the  taxpayer  of  the  oil  and 
gas  industiy  in  correctly  and  expeditiously  preparing  his  Federal 
tax  returns. 

Although  the  endeavor  was  made  to  anticipate  all  questions 
that  might  be  asked  regarding  the  law  and  regulations,  and  the 
latter  were  amplified  when  it  was  deemed  necessary  to  obtain 
the  desired  result,  it  is  recognized  that  such  a  manual  is  only 
general  and  cannot  cover  all  cases  that  may  exist.  The  Manual 
is  based  largely  upon  information  gathered  during  the  Fall  of  the 
year  1918  by  a  corps  of  geologists,  technologists  and  engineers. 
The  investigation  was  undertaken  primarily  to  furnish  a  basis 
for  arriving  at  valuations,  and  dcleption  and  depreciation  deduc- 
tions in  connection  with  oil  and  gas  properties.  Deeming  these 
subjects  to  be  of  the  greatest  importance,  the  Bureau  of  Internal 
Revenue  instituted  a  most  careful  inquiry.  All  fields  in  the 
United  States  were  canvassed.  Records  of  production  of  thou- 
sands of  properties  were  collected  and  tabulated.  These  were 
carefully  classified  and  studied  by  the  most  competent  and  experi- 
enced men  in  the  country  and  the  average  future  production 
curves  and  tables  of  valuation  data  were  produced  as  a  result  of 
this  study. 

In  compiling  the  Manual,  the  country  was  divided  into  seven 
districts,  each  of  which  was  handled  by  a  supervisor  and  several 
assistants.    These  were  the 


xii  INTRODUCTION 

Appalachian  Field. — G.  B.  Richardson,  of  the  U.  S.  Geological 
Survey,  assisted  by  Barniim  Brown,  L.  C.  Glenn,  Roswell  H. 
Johnson  and  others. 

Lima-Indiana  and  Illinois  Fields. — Thos.  E.  Savage,  Super- 
visor, assisted  by  J.  L.  Darnell,  L.  G.  Donnelly  and  others. 

Mid-Continent  Field. — J.  0.  Lewis,  Supervisor,  assisted  by 
H.  B.  Goodrich,  Calvin  T.  Moore,  James  H.  Hance,  W.  E.  Wrather 
and  others. 

Northern  Louisiana  Field. — A.  Faison  Dixon. 

Gulf  Coast  Field. — E.  DeGolyer,  Supervisor,  assisted  by 
A.  Faison  Dixon,  M.  W.  Mattison  and  others. 

The  Rocky  Mountain  District. — Cassius  A.  Fisher,  Supervisor, 
assisted  by  Arthur  Eaton,  C.  W.  Comstock  and  others. 

California. — Carl  H.  Beal,  Supervisor,  assisted  by  N.  R.  White, 
E.  D.  Nolan,  Robert  B.  Moran  and  others. 

The  foreign  countries  including  Mexico  were  covered  by 
V.  R.  Garfias. 

The  natural  gas  industry  was  handled  by  E,  W.  Shaw  of  the 
U.  S.  Geological  Survey,  assisted  by  S.  S.  Wyer,  A.  J.  Diescher, 
W.  J.  Judge,  W.  A.  Williams,  T.  B.  Gregory,  F.  R.  Clark,  E.  H. 
Finch  and  K.  D.  White. 

The  book  consists  of  three  parts. 

Part  I  deals  directly  with  the  Law  and  Regulations.  These 
as  they  relate  to  the  oil  and  gas  industry,  are  explained  and  nu- 
merous illustrations  and  examples  are  given  to  bring  out  their  appli- 
cation. Since  the  issuance  of  the  original  edition  of  the  Manual 
the  regulations  relating  to  discovery,  proven  tract  or  lease,  prop- 
erty disproportionate  in  value  and  proof  of  discovery  (Art.  220a 
and  221)  have  been  altered  by  the  adoption  of  Treasury  Decision 
2956  (December  2,  1919.)  The  new  regulations  regarding  these 
subjects  are  printed  on  pp.  44  to  46. 

Part  II  deals  with  the  question  of  depreciation  and  is  the 
result  of  the  work  of  a  committee  of  which  W.  A.  Williams,  of 
the  Fuel  Administration,  was  chairman,  assisted  by  Thos.  Cox, 
A.  W.  Ambrose,  H.  H.  Hill,  J.  P.  Smoots  of  the  Bureau  of  Mines 
and  L.  G.  Donnelly  of  the  Bureau  of  Internal  Revenue.  This 
chapter  should  assist  the  taxpayer  in  standardizing  his  classifi- 
cation of  equipment.  It  also  offers  suggestions  as  to  relative 
rates  of  depreciation  for  different  types  of  physical  property. 
The  rates  are  not  to  be  applied  indiscriminately  to  specific  cases 


INTRODUCTION  xui 

but  are  relative  only  and  the  Treasury  Department  is  in  no  way 
committed  to  accept  them  in  the  returns. 

Part  III  consists  of  descriptions  and  methods  of  estimating 
underground  oil  reserves,  especially  by  means  of  productive  curves. 
The  principal  paper  in  this  chapter  is  by  J.  0.  Lewis  and  C,  H. 
Beal  of  the  United  States  Bureau  of  Mines,  whose  work  along 
this  same  line  is  well  known  to  petroleum  engineers  throughout 
the  country.  A  collection  of  curves  and  tables  covering  many  of 
the  oil  fields  and  pools  in  the  United  States  accompanies  the  text. 
In  the  case  of  the  individual  districts,  these  curves  and  tables  were 
prepared  under  the  supervision  of  the  men  in  charge  of  the  dis- 
tricts in  which  the  pools  and  fields  are  situated.  The  curves  and 
tables  relating  to  the  Gulf  Coast  fields  were  not  included  in  the 
original  Manual;  the  tables  were  issued  subsequently  in  pam- 
phlet form;  the  curves  have  been  prepared  from  the  tables  especi- 
ally for  this  present  edition. 

The  curves  and  tables  are  intended  as  a  suggestion  for  the  guid- 
ance of  the  taxpayer  in  the  computation  of  his  depletion  allow- 
ance, which  in  turn  has  a  direct  bearing  on  the  amount  of  his 
tax.  They  are  not  to  be  applied  indiscriminately  to  specific  prop- 
erties, and  the  Treasury  Department  is  in  no  way  committed  to 
accept  estunates  based  upon  them.  Every  clami  for  deduction 
on  account  of  depletion  must  be  accompanied  by  a  detailed  state- 
ment of  production,  etc.,  upon  which  such  claim  is  based.  One 
of  the  principal  reasons  for  reprinting  the  INIanual  was  the  desire 
to  continue  the  availability  of  the  curves  and  tables  which  have 
so  many  other  uses  besides  that  of  forming  a  basis  for  tax  computa- 
tions. Among  these  uses  might  be  mentioned  appraisal  work  on 
properties  and  fields,  estimation  of  life  of  properties  and  fields, 
comparative  study  of  the  productivity  and  rate  of  decline  of 
fields,  etc. 

The  curves  and  •tables  are  based  upon  a  careful  systematic 
study  of  thousands  of  production  records ;  all  that  could  be  made 
available  in  the  limited  time  at  the  disposal  of  the  Bureau.  ]\Iany 
refinements  and  minor  corrections  are  desirable,  but  must  be 
delayed  until  more  complete  records  are  in  hand. 

The  work  of  compiling  and  editing  the  material  in  the  manual 
was  done  largely  by  A.  D.  Brokaw,  J.  L.  Darnell  and  L.  G.  Don- 
nelly. The  investigations  leading  to  the  preparation  of  the  man- 
ual and  its  compilation  and  publication  were  under  the  general 


xiv  INTRODUCTION 

supervision    of    the    writer,    then    Chief   of    the    Oil    and    Gas 
Section. 

Following  the  resignation  of  the  writer,  J.  L.  Darnell  was  made 
Chief  of  the  Natural  Resources  Branch  of  the  Internal  Revenue 
(including  Oil  and  Gas),  he  holding  the  position  until  March  1, 
1920,  when  he  was  succeeded  by  J.  C.  Dick.  Those  taking  part 
in  the  collection  and  compilation  of  the  material  on  which  the 
Manual  is  based,  in  addition  to  those  already  mentioned  are : 

California  Field:  Carl  H.  Beal.  Blackmar,  C.  A.,  Hall,  L.  S.; 
Johnson,  H.  R.;  Moran,  R.  B.;  Nolan,  F.  P.:  Gibson,  E.  J.; 
Arrell,  D.  B.;  White,  N.R.;  Kingsberrv.  J.  W. :  Boyd,  H.;  Clute, 
W.  S.;  Campbell,  Harry;  Trengrove,  S.  R. 

Rocky  Mountain  Field :  C.A.Fisher.  Lewis,  J.  W.;  Patton, 
H.  B.;  Eaton,  Arthur;  Prommel,  H.  W.;  Comstock,  Chas.  W. ; 
Prather,  R.  C;  Olds,  Thos.  H. 

Mid-Continent  Field:  J.  0.  Lewis.  Richards,  Ralph;  Samp- 
son, C.  E.;  Hance,  J.  H.;  Wrather,  W.  E.;  Hammer,  A.  A.; 
Lloyd,  E.  R.,  U.  S.  G.  S.;  Goodrich,  H.  B.;  Taylor,  C.  H.;  Moore, 
C.  T.;  McKnight,  R.  J.;  St.  Clair,  Stuart;  BUsingame,  Wade  A.; 
Caudill,  S.  J. 

Gulf  Field:  E.  DeGolyer  and  A.  F.  Dixon.  Hopkins,  O.  B.; 
Mattison,  M.  W.;  Prather,  W.  W. ;  Garfias,  V.  R. ;  Springer,  A.  R. ; 
Bentley,  W.  T.;  Kupferstein,  J.  T. 

lUinois  and  Lima-Indiana;  T.  E.  Savage.  Donnelly,  L.  G.; 
McConnell,  K.;  Darnell,  J.  L.;  Henney,  T.  V.;  Franklin,  Louis; 
Lines,  E.  F.;  Dawson,  Dan;  Barrett,  Edw.;  Blatchley,  R.  S.; 
Kahn,  J.  B.;  White,  K.D.;  Morgan,  D.M.;  Herald,  F.  A.;  Camp- 
bell, R.  M.;  Welsh,  LeRoy  G.;  Rasmus,  Walter;  Cox,  Eugene  G.; 
Eskil,  Rolf  M.;  Pengilly,  H.  E.;  Duval,  Wm.  C. 

Appalachian  Field:  Geo.  B.  Richardson.  Glenn,  L.  C;  Stout, 
W.;  Ports,  P.  L.;  Brown,  Barnum;  Hoeing,  J.  B.;  Melcher,  A.  F. ; 
Miller,  A.M.;  McElroy,  S.  M.;  Johnson,  R.  S.  H.;  Miller,  M.M.; 
Johnson,  F.  Arthur;  Herzig,  J.  A.,  Rev.  Agt. ;  Bender,  W.  J., 
Rev.  Agt.;  Bernard,  G.  A.,  Rev.  Agt.;  Jillson,  M.  R.;  Stephen- 
son, E.  A. 

Gas  Fields:  E.  W.  Shaw.  Clark,  F.  R.;  Moore,  R.  C; 
Wrather,  W.  E.;  Lee,  W.  T.;  Patton,  H.  B.;  Finch,  E.  H. 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTEY 


PART  I. 

AMPLIFICATION  OF  THE  LAW  AND  REGULATIONS. 
KINDS  OF  TAXES  IMPOSED. 

The  Revenue  Act  of  1918  levies  the  following  taxes  upon  the 
net  incomes  received  by  individuals  and  corporations  during  the 
taxable  year  1918: 

Normal  income  tax. — Section  210  of  the  Revenue  Act  of  1918 
levies  upon  the  net  income  of  every  individual,  a  normal  tax  at  the 
following  rates: 

For  the  calendar  year  1918,  12  per  cent  of  the  amount  of  the 
net  income  in  excess  of  the  credits  provided  in  section  216:  Pro- 
vided, That  in  the  case  of  a  citizen  or  resident  of  the  United  States 
the  rate  upon  the  first  $4,000  of  such  excess  amount  shall  be  6 
per  cent. 

Surtax. — In  addition  to  the  normal  tax  a  surtax  is  unposed  at 
the  rates  specified  in  the  statute  upon  the  net  income  of  every 
individual,  resident  or  nonresident.  In  determining  the  taxable 
net  income  for  the  purpose  of  the  surtax,  the  credits  provided  by 
section  216  of  the  statute  in  the  case  of  the  normal  tax  are  not 
applicable. 

Computation  of  surtax. — The  following  table  shows  the  surtax 
on  net  incomes  of  the  specified  amounts.  In  each  instance  the 
first  figure  of  net  income  in  the  net-income  cohmm  of  the  table  is 
to  be  excluded  and  the  second  figure  included.  The  percentage 
given  opposite  applies  to  the  excess  of  income  over  the  first  figure 
in  the  net-income  column,  and  the  simi  in  the  next  colunm  is  the 
tax  on  the  entire  difference  between  the  first  figure  and  the  second 
figure  in  the  net-income  column.  The  final  column  gives  the  total 
surtax  on  a  not  income  q(\\  il  to  the  second  figure  in  the  nel -income 


MANUAL   FOR   THE   OIL   AND   GAS   INDUSTRY 


Net  Income. 


$5,000  to  $0,000.... 

$6,000  to  $8,000 

$S,000  to  $10,000 

$10,000  to  $12,000 

$12,000  to  $14,000  ..  . 

$14,000  to  $16,000 

$16,000  to  S18,000 

$18,000  to  $20,000 

$20,000  to  $22,000 

$22,000  to  $24,000 

$24,000  to  $26,000 

$26,000  to  $28,000 .  .  . . 

$28,000  to  $30,000 

$30,000  to  $32,000 

$32,000  to  $34,000 

$34,000  to  $36,000 

$36,000  to  $38,000 

$38,000  to  $40,000 

$40,000  to  $42,000 

$42,000  to  $44,000 

$44,000  to  $46,000 

$46,000  to  $48,000 

$48,000  to  $50,000 

$50,000  to  $52,000 

$.'52,000  to  $54,000...  . 

$.54,000  to  $56,000 

$56,000  to  $58,000 

$58,000  to  $60,000..  .  . 

$60,000  to  $62,000 

$62,000  to  $64,000 

$64,000  to  $66,000 

$66,000  to  $68,000 

$68,000  to  $70,000 

$70,000  to  $72,000 

$72,000  to  .$74,000 

$74,000  to  $76,000 

$76,000  to  $78,000 

$78,000  to  $80,000 

$80,000  to  $82,000 

$82,000  to  $84,000 

$84,000  to  $86,000 

$86,000  to  $88,000..  .  . 

$88,000  to  .$90,000 

$90,000  to  $92,000 

$92,000  to  ,W4,000 

$94,000  to  $90,000 

$96,000  to  $98,000 

$98,000  to  $100,000... 
$100,000  to  $150,000.. 
$1.50,000  to  $200,000.. 
$200,000  to  $300,000.  . 
$300,000  to  $500,000.  . 
$500,000  to  $1,000,000 
$1,000,000  up 


Per  Cent. 

Surtax. 

Total 
Surtax. 

1 

$10 

$10 

2 

40 

0 

3 

60 

110 

4 

80 

190 

5 

100 

290 

6 

120 

410 

7 

140 

550 

8 

160 

710 

9 

180 

890 

10 

200 

1,090 

11 

220 

1,310 

12 

240 

1,550 

13 

260 

1,810 

14 

280 

2,090 

15 

300 

2,390 

16 

320 

2,710 

17 

340 

3,050 

18 

360 

3,410 

19 

380 

3,790 

20 

400 

4,190 

21 

420 

4,610 

22 

440 

5,050 

23 

460 

5,510 

24 

480 

5,990 

25 

600 

6,490 

26 

520 

7,010 

27 

540 

7,550 

28 

560 

8,110 

29 

580 

8,690 

30 

600 

9,290 

31 

620 

9,910 

32 

640 

10,550 

33 

660 

11,210 

34 

680 

11.890 

35 

700 

12,590 

36 

720 

13,310 

37 

740 

14,050 

38 

760 

14,810 

39 

780 

15,590 

40 

800 

16,390 

41 

820 

17.210 

42 

840 

18,050 

43 

860 

18,910 

44 

880 

19,790 

45 

900 

20,690 

46 

920 

21,610 

47 

940 

22,550 

48 

960 

23,510 

52 

26,000 

49,510 

56 

28,000 

77,510 

60 

60,000 

137,510 

63 

126,000 

263,510 

64 

320,000 

583,510 

65 

MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY  3 

column.  The  tax  for  any  amount  of  net  income  not  shown  in  the 
table  is  computed  by  adding  to  the  total  surtax  for  the  largest 
amount  shown  which  is  less  than  the  income,  the  surtax  upon  "^he 
excess  over  that  amount  at  the  rate  indicated  in  the  table.  For 
example,  if  the  amount  of  net  income  is  S63,128,  the  surtax  is  the 
sum  of  $8,690  (the  surtax  upon  $62,000  as  shown  by  the  table) 
plus  30  per  cent  of  $1,128,  or  $338.40,  making  a  total  surtax  of 
$9,028.40. 

LIMITS  OF  SURTAX  AND  WAR  EXCESS  PROFITS  TAX  IN  CASE  OF 

SALE. 

Sections  211  (b)  and  337  of  the  Revenue  Act  of  1918  provide 
that  "in  the  case  of  a  bona  fide  sale  of  mines,  oil  or  gas  wells,  or  any 
interest  therein,  where  the  principal  value  of  the  property  has  been 
demonstrated  by  prospecting  or  exploration  and  discovery  work, 
done  by  the  taxpayer,  the  portion  of  the  tax  imposed  by  this  section 
attributable  to  such  sale  shall  not  exceed  20  per  cent  of  the  selling 
price  of  such  property  or  interest." 

Regulations  45,  article  13 — "Surtax  on  the  sale  of  mineral 
ddosits. — ^Where  the  taxpayer  by  prospecting  and  locating  clamis, 
or  by  exploring  and  discovering  undeveloped  claims,  has  demon- 
strated the  principal  value  of  mines,  oil  or  gas  wells,  which  prior  to 
his  efforts  had  a  merely  nominal  value,  the  portion  of  the  surtax 
attributable  to  a  sale  of  such  property  or  of  the  taxpayer's  interest 
therein  shall  not  exceed  20  per  cent  of  the  selling  price.  Explora- 
tion work  alone  without  discovery  is  not  sufficient  to  bring  a  case 
within  this  provision.  Shares  of  stock  in  a  corporation  owning 
mines,  oil  or  gas  wells  do  not  constitute  an  interest  in  such  property^ 
To  determine  the  application  of  this  provision  to  a  particular  case, 
the  taxpayer  should  first  compute  the  surtax  in  the  ordinary  way 
upon  his  net  income,  including  his  net  income  from  any  such  sale. 
The  proportion  of  the  surtax  indicated  by  the  ratio  which  the 
taxpayer's  net  income  from  the  sale  of  the  property,  computed  as 
prescribed  in  article  715  of  Regulations  45,  bears  to  his  total  net 
income  is  the  portion  of  the  surtax  attributable  to  such  sale,  and  if 
it  exceeds  20  per  cent  of  the  selling  price  of  the  property  such 
portion  of  the  surtax  shall  be  reduced  to  that  amount." 

In  the  case  of  a  corporation  the  war  and  excess  profits  tax 
applicable  to  such  a  sale  is  limited  to  20  per  cent  of  the  selling  price 
in  accordance  with  section  337  of  the  law. 


4  MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY 

What  the  Taxpayer  Must  Prove. 

The  taxpayer  in  order  to  take  advantage  of  this  clause  in  the 
law  must  prove — 

(q)  A  bona  fide  sale. 

X&)  That  the  principal  value  of  the  property  has  been  demon- 
strated by  prospecting  or  exploration  and  development  work  done 
by  the  taxpayer. 

This  benefit  will  accrue  only  to  the  holdings  of  the  taxpayer 
making  the  discovery. 

In  order  to  meet  the  requirements  of  the  case  to  the  satis- 
faction of  the  Commissioner,  the  taxpayer  will  be  required  to  sub- 
mit the  information  called  for  in  Schedules  III,  VI,  and  VIII  on 
pages  59,  62,  and  65  of  the  Manual. 

Tax  On  Corporations} 

Section  230  of  the  Revenue  Act  of  1918  levies,  in  lieu  of  the 
taxes  imposed  by  section  10  of  the  Revenue  Act  of  1916,  as 
amended  by  the  Revenue  Act  of  1917  and  by  section  4  of  the 
Revenue  Act  of  1917,  upon  the  net  income  of  every  corporation 
not  specifically  exempted  a  tax  at  the  following  rates : 

(1)  For  the  calendar  year  1918,  12  per  cent  of  the  amount  of 
the  net  income  in  excess  of  the  credits  provided  in  section  236;  and 

(2)  For  each  calendar  year  thereafter  10  per  cent  of  such  excess 
amount.     See  Part  II  of  the  Regulations, 

War-Profits  and  Excess-Profits  Tax. 

Section  301  (a)  of  the  Revenue  Act  of  1918  levies,  in  lieu  of  the 
tax  imposed  by  Title  II  of  the  Revenue  Act  of  1917,  but  in  ad- 
dition to  the  other  taxes  imposed  by  this  act,  upon  the  total  net 
income  of  every  corporation  not  specifically  exempted,  for  the  tax- 
able year  1918  a  tax  equal  to  the  sum  of  the  following: 

First  bracket. — Thirty  per  cent  of  the  amount  of  the  net  income 
in  excess  of  the  excess  profits  credits  (as  determined  under  sec. 
312)  and  not  in  excess  of  20  per  cent  of  the  invested  capital. 

'  In  all  cases  involving  returns  of  corporations  Part  II  of  Regulations  45 
ehould  be  consulted. 


MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY  5 

Second  bracket. — Sixty-five  per  cent  of  the  amount  of  the  net 
income  in  excess  of  20  per  cent  of  the  invested  capital. 

Third  bracket. — ^The  simi,  if  any,  by  which  80  per  cent  of  the 
amount  of  the  net  income  in  excess  of  the  war-profits  credits 
(determined  under  sec.  311)  exceeds  the  amount  of  the  tax  com- 
puted under  the  first  and  second  brackets.  See  Part  II  of  the 
Regulations. 

GROSS  INCOME  AND  NET  INCOME. 

Gross  income  includes  all  gains  and  profits  and  income  from  any 
source  whatever,  subject  to  the  specific  exemptions  listed  in  section 
213  (b)  and  section  231  of  the  Revenue  Act  of  1918,  actually  re- 
ceived for  the  year  for  which  the  return  is  rendered,  whether 
received  in  cash  or  its  equivalent. 

Net  income  is  the  amount  remaining  after  all  allowable  deduc- 
tions  (as  listed  in  sec.  214  (a)  and  (b)  or  sec.  234  (a)  and  (b)  have 
been  made  from  gross  income. 

BASIS  FOR  DEDUCTIONS. 

Certain  deductions  from  gross  income  are  based  upon  the 
"Capital  Sum";  credits  are  based  upon  "Invested  Capital."  It  is 
necessary  that  these  terms  be  clearly  understood  by  the  taxpayer 
in  order  to  avoid  confusion  in  making  returns. 

In  general,  the  deductions  from  gross  income  allowed  cor- 
porations are  the  same  as  allowed  individuals,  except  that  corpora- 
tions may  deduct  dividends  received  from  other  corporations  sub- 
ject to  the  tax  and  may  not  deduct  charitable  contributions,  and 
that  insurance  companies  are  permitted  special  deductions. 

INVESTED  CAPITAL. 

The  invested  capital  is  defined  in  section  326  of  the  Revenue 
Act  of  1918  as^(l)  actual  cash  bona  fide  paid  in  for  stock  or  shares; 
(2)  cash  value  of  property,  other  than  cash,  bona  fide  paid  in  for 
stock  or  shares  (as  limited  by  the  statute) ;  and  (3)  paid  in  or  iwrncd 
surplus  and  undivided  profits,  not  including  surplus  and  un- 
divided profits  earned  during  the  year. 

The  surplus  and  undivided  profits,  if  not -correctly  reflected  in 
the  taxpayer's  accounts,  may  be  adjusted  in  accordance  with  Reg- 


6  MANUAL  FOR   THE  OIL  AND   GAS   INDUSTRY 

ulations  45.  Several  of  the  articles  which  must  ordinarily  be  con- 
sidered are  set  out  below. 

Regulations  45,  article  839.  Surplus  and  undivided  profits: 
Allowance  for  depletion  and  depreciation. — Depletion,  like  depre- 
ciation, must  be  recognized  in  all  cases  in  which  it  occurs.  Deple- 
tion attaches  to  each  unit  of  mineral  or  other  property  removed, 
and  the  denial  of  a  deduction  in  computing  net  income  under  the 
Act  of  August  5,  1909,  or  the  limitation  upon  the  amount  of  the 
deduction  allowed  under  the  Act  of  October  3,  1913,  does  not 
relieve  the  corporation  of  its  obligation  to  make  proper  provision 
for  depletion  of  its  property  in  computing  its  surplus  and  undivided 
profits. 

Adjustments  in  respect  of  depreciation  or  depletion  in  prior 
years  will  be  made  or  permitted  only  upon  the  basis  of  affirmative 
evidence  that  as  at  the  beginning  of  the  taxable  year  the  amount 
of  depreciation  or  depletion  written  off  in  prior  years  was  insuffi- 
cient or  excessive,  as  the  case  may  be. 

Where  deductions  for  depreciation  or  depletion  have  either  on 
the  books  of  the  corporation  or  in  its  returns  of  net  income  been 
included  in  the  past  in  expense  or  other  accounts,  rather  than 
specifically  as  depreciation  or  depletion,  or  where  capital  expendi- 
tures have  been  charged  to  expense  in  lieu  of  depreciation  or  de- 
pletion, a  statement  indicating  the  extent  to  which  this  practice 
has  been  carried  should  accompany  the  return. 

Regulations  45,  article  842.  Surplus  and  undivided  profits 
property  paid  in  and  subsequently  written  off. — Where  tangible  or 
intangible  property  has  been  paid  m  to  a  corporation  for  stock  or 
shares  or  as  paid-in  surplus  and  has  subsequently  been  in  whole  or 
in  part  written  off  the  books,  the  amount  so  written  off  may,  upon 
evidence  satisfactory  to  the  Commissioner,  be  restored  to  the 
capital  or  surplus  account  subject  to  the  following  limitations: 

(1)  The  amount  restored  must  be  reduced  by  a  proper  deduc- 
tion for  any  depreciation,  obsolescence,  or  depletion;  and 

(2)  The  aggregate  amount  mcluded  in  computing  invested 
capital  on  account  of  such  property  shall  not  exceed  the  amount 
which  might  have  been  included  if  such  property  had  not  been 
written  off. 

Regulations  45,  article  844.  Surplus  and  undivided  profits 
reserve  for  depreciation  or  depletion. — ^If  any  reserves  for  depre- 
ciation or  for  depiction  are  included  in  the  surplus  account  it 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY  7 

should  be  analyzed  so  as  to  separate  reserves  and  leave  only  real 
surplus.  Reserves  for  depreciation  or  depletion  can  not  be  in- 
cluded in  the  computation  of  invested  capital,  except  to  the  follow- 
ing extent : 

(1)  Excessive  depletion  or  depreciation  included  therein  and 
which  if  charged  off  could  be  restored  under  article  871  may  be 
included  in  the  computation  of  invested  capital;  and. 

(2)  Where  depreciation  or  depletion  is  computed  on  the  value 
as  of  March  1,  1913,  or  as  of  any  subsequent  date,  the  proportion 
of  depreciation  or  depletion  representing  the  realization  of  appre- 
ciation of  value  at  March  1,  1913,  or  such  subsequent  date  may,  if 
undistributed  and  used  or  employed  in  the  business,  be  treated  as 
surplus  and  included  in  the  computation  of  invested  capital. 

For  the  purpose  of  computing  invested  capital,  depreciation  or 
depletion  computed  on  the  value  as  of  March  1,  1913,  or  as  of  any 
subsequent  date,  shall,  if  such  value  exceeded  cost,  be  deemed  a 
pro  rata  realization  of  cost  and  appreciation  and  be  apportioned 
accordingly.  Except  as  above  provided,  value  appreciation  (even 
though  evidenced  by  an  appraisal)  which  has  not  been  actually 
realized  and  reported  as  income  for  the  purpose  of  the  income  tax 
can  not  be  included  in  the  computation  of  invested  capital,  and  if 
already  reflected  in  the  surplus  account  it  must  be  deducted  there- 
from. 

The  term  Cajntal  Sum  is  here  applied  to  the  total  amount  re- 
turnable to  the  taxpayer  through  depletion,  depreciation,  and  qb-^ 
solescence  allowances.  It  is  to  be  clearly  distinguished  from  the 
term  "Invested  Capital,"  which  is  the  basis  for  the  determination 
of  war-profits  credits  and  excess-profits  credits  of  corporations. 
"Invested  capital"  is  the  actual  cash  or  its  equivalent,  paid  in,  plus 
undistributed  surplus  profits,  and  no  appreciation  in  the  value  of 
any  asset  may  be  included  except  as  provided  in  article  844  (2). 

"CAPITAL   SUM"  AND  "INVESTED   CAPITAL." 

The  "capital  sum"  has  no  necessary  relation  to  the  "invested 
capital."  It  may  represent  the  investment  of  funds  belonging  to 
the  taxpayer,  or  the  investment  of  l)orrowed  fimds,  which  have 
no  relation  to  invested  capital ;  under  the  provisions  of  the  law  and 
regulations,  the  capital  sum  may  include  amounts  based  upon  the 
right  of  valuation  as  of  March  1,  1913,  or  within  30  days  after  the 


\ 


8  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

discovery  of  oil  or  ^as  by  the  taxpayer.     (See  Proof  of  Discovery, 
page  45.) 

Where  such  valuations  are  allowable,  they  have  no  application 
to  invested  capital,  except  in  accordance  with  article  844  (2)  of 
Regulations  45,  and  may  not  be  used  for  any  purpose  other  than  j,s 
a  basis  for  depletion,  depreciation,  and  obsolescence,  or  as  a  basis 
upon  which  to  determine  the  gain  or  loss  arising  from  the  sale  or 
surrender  of  property  acquired  prior  to  March  1,  1913.  With 
respect  to  any  allowance  for  amortization  the  basis  is  the  cost  of 
property  acquired  after  April  5,  1917,  and  no  amount  may  be 
added  on  account  of  revaluation. 

The  application  of  these  principles  is  indicated  in  the  following: 
A  corporation  had  a  paid-up  capital  stock  of  $50,000.  This 
amount  was  invested  in  oil  and  gas  property  and  in  addition  the 
corporation  had  incurred  liabilities  due  to  developing  the  property 
and  the  purchasing  of  equipment  at  the  beginning  of  the  taxable 
year  amounting  to  $50,000.  The  property  was  found  to  have  a 
value  of  $150,000  in  accordance  with  the  valuation  accepted  by  the 
Commissioner.  The  allowable  deductions  for  depletion  and  depre- 
ciation in  determining  the  net  income  of  the  corporation  are  com- 
puted on  the  value  of  $150,000.  The  actual  invested  capital  for 
the  purpose  of  calculating  the  tax  due  for  the  taxable  year  from  the 
corporation  is  $50,000.  However,  in  the  succeeding  taxable  year 
a  part  of  the  aggregate  allowance  for  depletion  and  depreciation 
(proportionate  to  the  part  of  the  capital  smn  representing  appre- 
ciation) may  be  included  in  invested  capital  in  accordance  with  the 
provision  of  article  844  (2)  of  Regulations  No.  45.  The  following 
statement  is  prepared  to  illustrate  the  application  of  the  law  to 
the  case  cited: 

Assuming  the  total  deduction  for  depletion,  depreciation,  and  oboles- 
cence  from  the  gross  income  to  be  10  per  cent  of  the  valuation 
accepted  by  the  Commissioner,  the  amount  deductible  for  the  tax- 
able year  would  be : $15,000 

Amount  of  depiction,  depreciation,  and  obsolescence  calculated  on  the 

cost  of  the  property  is 10,000 

The  amount  of  realized  appreciation  which  may  be  added  to  invested 

capital  for  the  succeeding  year  is 5,000 

Assuming  that  all  the  earnings  are  distributed,  except  the  depletion 
and  depreciation  reserves,  at  the  beginning  of  the  succeeding  tax- 
able year,  the  invested  capital  would  be 55,000 

The  cost  of  the  property  would  be 90,000 

The  ai)i)rcciation  in  value  would  be 45,000 


MANUAL   FOR  THE  OIL  AND   GAS   INDUSTRY  9 

Physical  property  is  defined  as  all  equipment  having  an  inven- 
tory or  salvage  value  and  subject  to  removal  from  the  property, 
such  as  buildings,  bridges,  and  power  plants;  derricks,  c^ings^ 
drilling  equipment  (cable  and  rotary),  and  pumping  equipment, 
including  engines,  boilers,  tubing,  and  rods;  flow  lines,  and  con- 
nections on  wells,  tanks_attached  to  wells,  and  other  tankage_of 
steel,  wood,  or  concrete;  cleaning  and  pulling  equipment;  salt^ 
water  equipment;  refineries,  treating  and  reducing  plants,  includ- 
ing casinghead  gas  plants;  telegraph  and  telephone  lines,  pipe 
lines  and  tank  cars,  and  all  other  equipment  used  in  the  produc- 
tion^ reduction,  conservation,  or  transportation  of  oil  and  gas  or 
their  products. 

Cost  of  property  includes  all  amounts  (in  cash  or  its  equivalent) 
paid  for  and  incident  to  the  esta])lishment  of  title  and  acquisition 
of  the  lease  or  freehold,  as  the  case  may  be,  such  as^— 

Purchase  price  of  lease  or  freehold. 

Salaries  or  commissions  paid  to  brokers  or  agents. 

Fees  to  geologists,  attorneys,  surveyors,  etc.,  for  examination 
and  defense  of  title,  establishing  boundaries,  etc.,  State^  and 
county  fees  for  recording  and  legalizing  transfers,  and  all  other 
payments  made  in  acquiring  and  establishing  title  to  the  properties. 

Cost  of  development  comprises  all  payments  made  for  and 
incident  to  the  drilling  of  wells,  such  as  cost  of — 

(1)  Physical  property. 

(2)  Geological  and  other  surveys,  made  subsequent  to  ac- 
quisition. 

(3)  Roads. 

(4)  Water  supplies. 

(5)  Hauling. 

(6)  Wages. 

(7)  Drilling. 

(8)  Shooting. 

(9)  Overhead  charges  ^incident  to  drilling  of  wells). 

(10)  Fuel;  and 

(11)  All  other  similar  expenditures^ 

Both  "Cost  of  Property"  and  "Cost  of  Development,"  in  so  far 
as  they  have  not  been  decreased  by  allowable  deductions,  are 
chargeable  to  capital  sum  and  are  returnable  through  the  several 
allowable  deductions.  Structures  and  equipment  may  also  be 
included  in  capital  assets  and  arc  returnable  through  depreciation, 


10  MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY 

In  the  case  of  revaluations  as  of  March  1,  1913,  or  within  30  days  of 
a  discovery  ])y  the  taxpayer  made  subsequent  to  February  28, 
1913,  th(^  \:ilu('  thus  cslabhshed  phis  subsequent  costs  not  other- 
wise deducted  becomes  the  total  of  "Capital  Sum.''  This  revalu- 
ation, however,  does  not  affect  the  Invested  Capital,  as  explained 
on  page  7. 

Development  costs  (except  the  cost  of  physical  property)  may 
be  deducted  as  an  expense  in  the  year  in  which  they  are  paid  out  or 
at  the  option  of  the  taxpayer  may  be  charged  to  capital  sum. 
Election  once  made  under  this  option  is  final  and  will  control  the 
returns  for  all  subsequent  years. 

EXPENSES. 

Expense  includes  all  amounts  paid  out  (exclusive  of  amounts 
paid  for  physical  property  and  development  charged  to  Capital 
Sum)  incident  to  the  development  and  operation  of  producing 
properties  and  the  preparation  of  their  product  for  market,  such  as 
costs  of  pumping,  cleaning,  reshooting  (including  cost  of  torpedoes), 
gauging,  storing,  treating,  reducing,  repairs  and  maintenance, 
transporting,  refining,  conserving,  marketing,  overhead  expense, 
insurance,  etc. 

The  cost  of  repairs  and  replacements  made  necessary  through 
deterioration  of  equipment  may  be  charged  off  as  expense,  but  if 
this  is  done  the  amount  allowed  as  a  depreciation  deduction  will  be 
reduced. 

In  all  cases  items  of  expense  must  be  charged  off  as  such  for  the 
year  incurred  and  can  neither  be  deducted  from  the  income  of  sub- 
sequent years  as  expense  nor  added  to  Capital  Sum. 

Repairs. — The  cost  of  incidental  repairs  which  neither  mater- 
ially add  to  the  value  of  the  property  nor  appreciably  prolong  its 
life,  but  keep  it  in  an  ordinary  efficient  operating  condition,  may 
be  deducted  as^xj)ense,  provided  the  plant  or  property  account  is 
not  increased  by  the  amount  of  such  expenditures.  Repairs  in 
the  nature  of  replacements,  to  the  extent  that  they  arrest  deteriora- 
tion and  appreciably  prolong  the  life  of  the  property,  should  be 
charg(Hl  against  the  depreciation  reserve. 

Improvements  and  betterments. — Amounts  expended  for 
additions  and  betterments  or  for  furnitm-e  and  fixtures,  which 
constitute  an  increase  in  capital  assets  or  add  to  their  value,  are 


MANUAL   FOR  THE   OIL  AND   GAS  INDUSTRY  11 

not  a  proper  deduction,  but  such  expenditures  when  capitalized 
may  be  reduced  through  annual  depreciation  deductions. 

COMPENSATION  FOR  PERSONAL  SERVICES. 

Among  the  ordinary  and  necessary  expenses  paid  or  incurred  in 
carrying  on  any  trade  or  business  may  be  included  a  reasonable 
allowance  for  salaries  or  other  compensation  for  personal  services 
actually  rendered.  The  test  of  deductibility  in  the  case  of  com- 
pensation payments  is  whether  they  are  reasonable  and  are  in  fact 
payments  purely  for  services. 

Bonuses  to  employees. — Gifts  or  bonuses  to  employees  will 
constitute  allowable  deductions  from  gross  income  when  such 
payments  are  made  in  good  faith  and  as  additional  compensation 
for  the  services  actually  rendered  by  the  employees,  provided  such 
payments,  when  added  to  the  stipulated  salaries,  do  not  exceed  a 
reasonable  compensation  for  the  services  rendered. 

Donations  made  to  employees  and  others,  which  do  not  have 
in  them  the  element  of  compensation  or  are  in  excess  of  reasonable 
compensation  for  services,  are  considered  gratuities  and  are  not 
deductible  from  gross  income. 

TIME  FOR  DEDUCTION  OF  CHARGES. 

Each  year's  return,  so  far  as  practicable,  both  as  to  gross  income 
and  deductions  therefrom,  should  be  complete  in  itself,  and  tax- 
payers are  expected  to  make  every  reasonable  effort  to  ascertain  the 
facts  necessary  to  make  a  correct  return. 

The  expenses,  liabilities  or  deficit  of  one  year  can  not  be  used  to 
reduce  the  income  of  a  subsequent  year.  A  person  making  returns 
on  an  accrued  basis  has  the  right  to  deduct  all  authorized  allow- 
ances, whether  paid  in  cash  or  set  up  as  a  Hability,  and  it  follows 
that  if  he  does  not  within  any  year  pay  or  accrue  certain  of  his 
expenses,  interest,  taxes,  or  other  charges,  and  make  no  deduction 
therefor,  he  can  not  deduct  from  the  income  of  the  next  or  any 
subsequent  year  any  amounts  then  paid  in  liciuidation  of  the 
previous  year's  liabilities.  A  loss  from  theft  or  embezzlement 
occurring  in  one  year  and  discovered  in  another  is  deductible  only 
for  the  year  of  its  occurrence. 

Any  amount  paid  pursuant  to  a  judgment  or  otherwise  on 
account  of  damages  for  personal  injuries,  patent  infringements,  or 


12  MANUAL  FOR   THE   OIL  AND   GAS   INDUSTRY 

otherwise,  is  deductible  from  gross  income  when  the  claim  is 
liquidated  or  put  in  judgment  or  actually  paid,  less  any  amount  of 
such  damages  as  may  have  been  compensated  for  by  insurance  or 
otherwise. 

If  subsequent  thereto,  however,  a  taxpayer  has  for  the  iSrst 
time  ascertained  the  amount  of  a  loss  sustained  during  a  prior 
taxable  year  and  not  deducted  from  the  gross  income  therefor,  he 
may  render  an  amended  return  for  such  preceding  taxable  year, 
including  such  amount  of  loss  in  the  deductions  from  gross  income, 
and  may  file  a  claim  for  refund  for  the  excess  tax  paid  by  reason  of 
the  failure  to  deduct  such  loss  in  the  original  return.  Provided 
that  no  such  credit  or  refund  shall  be  allowed  or  made  after  five 
years  from  the  date  when  the  return  was  due,  unless  before  the 
expiration  of  such  five  years  a  claim  therefor  is  filed  by  the  tax- 
payer. 

TAXES. 

Federal  taxes  (except  income,  war-profits,  and  excess-profits 
taxes),  State  and  local  taxes  (except  taxes  assessed  against  local 
benefits  of  a  kind  tending  to  increase  the  value  of  the  property 
assessed),  and  taxes  imposed  by  possessions  of  the  United  States 
or  by  foreign  countries  (except  the  amount  of  income,  war-profits, 
and  excess-profits  taxes  allowed  as  a  credit  against  the  tax),  are 
deductible  from  gross  income.  See  section  222  of  the  statute  and 
articles  381  et  seq.  of  Regulations  45  as  to  tax  credits. 

Postage  is  not  a  tax.  Amounts  paid  to  States  under  secured- 
debts  laws  in  order  to  render  securities  tax  exempt  are  deductible. 
Automobile  license  fees  are  ordinarily  taxes. 

LOSSES. 

Losses  sustained  during  the  taxable  year  and  not  compensated 
for  by  insurance  or  otherwise  are  fully  deductible  (except  by  non- 
resident aliens)  if — 

(a)  Incurred  in  the  taxpayer's  trade  or  business; 

(6)  Incurred  in  any  transaction  entered  into  for  profit;  or 

(c)  Arising  from  fires,  storms,  shipwreck,  or  other  casualty,  or 
from  theft. 

They  must  usually  be  evidenced  by  closed  and  completed  trans- 
actions. In  the  case  of  the  sale  of  assets  the  loss  will  be  the  differ- 
ence between  the  cost  thereof,  less  depreciation  sustained  since 


MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY  13 

acquisition,  or  the  value  as  of  March  1,  1913,  if  acquired  before  that 
date,  less  depreciation  since  sustained,  and  the  price  at  which  they 
were  disposed  of. 

When  the  loss  is  claimed  through  the  destruction  of  property  by 
fire,  flood,  or  other  casualty,  the  amount  deductible  will  be  the 
difference  between  the  cost  of  the  property;  or  its  value  as  of 
March  1,  1913,  and  the  salvage  value  thereof,  after  deducting  from 
the  cost  or  value  as  of  March  1,  1913,  the  amount,  if  any,  which  has 
been  or  should  have  been  set  aside  and  deducted  in  the  current  year 
and  previous  years  from  gross  income  on  account  of  depreciation, 
and  which  has  not  been  paid  out  in  making  good  the  depreciation 
sustained.  But  the  loss  should  be  reduced  by  the  amount  of  any 
insurance  or  other  compensation  received. 

Losses  in  illegal  transactions  are  not  deductible. 

Losses  of  oil  and  gas  are  of  two  kinds:  (a)  Those  which  arc 
unforeseen  or  unavoidable,  such  as  losses  sustained  through  fire  or 
accident;  and  (b)  losses  that  are  anticipated  and  recognized  as 
unavoidable  under  operating  conditions,  such  as  evaporation  of 
oil  in  storage,  ordinary  leakage,  refinery  losses,  etc. 

Usually  the  latter  class  are  indeterminate  as  to  amount  and  are 
absorbed  either  implicitly  or  explicitly  in  current  operating  ex- 
penses or  in  cost  of  the  oil  or  gas.  Indeterminate  losses  may  not  be 
deducted  from  gross  income. 

DEPRECIATION. 

Quotation  from  law. — Section  214  (a)  (10): 

In  the  case  of  mines,  oil  and  gas  wells,  other  natural  deposits,  and  timber  a  / 
reasonable  allowance  for  depletion  .  .  .  and  for  depreciation  of  imjirove- 
ments,  according  to  the  peculiar  conditions  of  each  case,  based  upon  cost 
including  cost  of  development  not  otherwise  deducted. 

Definition.^ — ^The  term  depreciation  is  used  to  cover  the  waste  of 
assets  due  to  exhaustion,  wear  and  tear,  and  obsolescence  of 
property,  and  is  not  to  be  confused  with  the  depletion  of  the 
natural  deposits  of  oil  and  gas  due  to  the  removal  of  these  com- 
modities in  the  course  of  exploitation  of  any  property. 

Depreciation  Allowa7ice. 

Regulations  45,  article  161. — A  reasonable  allowance  for  the 
exhaustion,  wear  and  tear,  and  obsolescence  of  property  used  in 


14  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

tlic  tra(l(^  or  business  may  be  deducted  from  gross  income.  The 
proper  allowance  for  such  depreciation  of  any  property  used  in  the 
trade  or  business  is  that  amount  which  should  be  set  aside  for 
the  taxable  year  in  accordance  with  a  consistent  plan  by  which 
the  aggregate  of  such  amounts  for  the  useful  life  of  the  property 
in  the  business  will  suffice,  with  the  salvage  value  at  the  end  of  such 
useful  life,  to  provide  in  place  of  the  property  its  cost  or  its  value  as 
of  March  1,  1913,  if  acquired  by  the  taxpayer  before  that  date. 

Depreciable  Property. 

Regulations  45,  article  162. — The  necessity  for  a  depreciation 
allowance  arises  from  the  fact  that  certain  property  used  in  the 
business  gradually  approaches  a  point  where  its  usefulness  is 
exhausted.  The  allowance  should  be  confined  to  property  of  this 
nature.  In  the  case  of  tangible  property  it  applies  to  that  which  is 
subject  to  wear  and  tear,  to  decay  or  decline  from  natural  causes, 
to  exhaustion,  and  to  obsolesence  due  to  the  normal  progress  of  the 
art  or  to  becoming  inadequate  to  the  growing  needs  of  the  business. 
It  does  not  apply  to  inventories  or  to  stock  in  trade,  nor  to  land 
apart  from  the  improvements  or  physical  development  added  to  it. 
It  does  not  apply  to  bodies  of  minerals  which  through  the  process 
of  removal  suffer  depletion,  other  provisions  for  this  being  made  in 
the  statute.  Property  kept  in  repair  may,  nevertheless,  be  the 
subject  of  a  depreciation  allowance.  The  deduction  of  an  allow- 
ance for  depreciation  is  limited  to  property  used  in  the  taxpayer's 
trade  or  business.  No  such  allowance  may  be  made  in  respect  to 
automobiles  or  other  vehicles  used  chiefly  for  pleasure,  a  building 
used  by  the  taxpayer  solely  as  his  residence,  nor  in  respect  of 
furniture  or  furnishings  therein,  personal  effects,  or  clothing;  but 
properties  and  costumes  used  exclusively  in  a  business,  such  as  a 
theatrical  business,  may  be  the  subject  of  a  depreciation  allowance. 

Depreciation  of  Intangible  Property. 

Regulations  45,  article  163. — Intangibles,  the  use  of  which  in 
the  trade  or  business  is  definitely  limited  in  duration,  may  be  the 
subject  of  a  depreciation  allowance.  Examples  are  patents  and 
copyrights  and  limited  leases,  licenses,  and  franchises. 


MANUAL   FOR   THE   OIL  AND    GAS   INDUSTRY  15 

Capital  Sum  Returnable  through  Depreciation  Allowances. 

Regulations  45,  article  165. — The  capital  sum  to  be  replaced  by- 
depreciation  allowances  is  the  cost  of  the  property  in  respect  of 
which  the  allowance  is  made,  except  that  in  the  case  of  property 
accLuiredJby  the  taxpayer  prior  to  March  1,  1913,  the  capital  sum 
to  be  replaced  is  the  fair  market  value  of  the  property  as  of  that 
date.  In  the  absence  of  proof  to  the  contrary,  it  will  be  assumed 
that  such  value  as  of  March  1,  1913,  is  the  cost  of  property  less 
depreciation  up  to  that  date.  To  this  sum  should  be  added  from 
time  to  time  the  cost  of  improvements,  additions,  and  betterments, 
the  cost  of  which  is  not  deducted  as  an  expense  in  the  taxpayer's 
return,  and  from  it  should  be  deducted  from  time  to  time  the 
amount  of  any  definite  loss  or  damage  sustained  by  the  property 
through  casualty,  as  distinguished  from  the  gradual  exhaustion  of 
its  utility  which  is  the  basis  of  the  depreciation  allowance.  In  the 
case  of  the  acquisition  after  March  1,  1913,  of  a  combination  of 
depreciable  and  non-depreciable  property  for  a  limip  price,  as,  for 
example,  land  and  buildings,  the  capital  sum  to  be  replaced  is 

limited  to  that  part  of  the  lump  price  which  represents  the  value 

of  the  depreciable  property  at  the  time  of  such  acquisition,  such 
value  to  be  ascertained,  if  necessary,  by  estmiate. 

Method  of  Computing  Depreciation  Allowances. 

Regulations  45,  article  166. — The  capital  sum  to  be  replaced 
should  be  charged  off  over  the  useful  life  of  the  property  either  in 
equal  annual  installments  or  in  accordance  with  any  other  recog- 
nized trade  practice,  such  as  an  apportionment  of  the  capital  sum 
over  units  of  production.  Whatever  plan  or  method  of  apportion- 
ment is  adopted  must  be  reasonable  and  should  be  described  in  the 
return. 

Modification  of  Method  of  Computing  Depreciation. 

Regulations  45,  article  167. — If  it  develops  that  the  useful  life 
of  the  property  has  been  underestimated,  the  plan  of  computing 
depreciation  should  be  modified  and  the  balance  of  the  cost  of  the 
property,  or  its  fair  market  value  as  of  March  1,  1913,  not  already 
provided  for  through  a  depreciation  reserve,  should  be  spread 
over  the  estimated  remaining  life  of  the  property. 


16  MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY 

A  taxpayer  who  in  computing  depreciation  allowance  in  returns 
for  years  prior  to  1918  has  not  taken  ordinary  obsolescence  into 
consideration  may  for  the  year  1918,  and  subsequent  years,  revise 
the  estimate  of  the  useful  life  of  any  property  so  as  to  allow  for  such 
future  obsolescence  as  may  be  expected  from  experience  to  result 
from  the  normal  progress  of  the  art.  No  modification  of  the 
method  should  be  made  on  account  of  changes  in  the  market  value 
of  the  property  from  time  to  time,  such  as,  on  the  one  hand,  loss  in 
rental  value  of  buildings  due  to  deterioration  of  the  neighborhood, 
or,  on  the  other  hand,  appreciation  due  to  increased  demand.  The 
conditions  affecting  such  market  values  should  be  taken  into 
consideration  only  so  far  as  they  affect  the  estimate  of  the  useful 
life  of  the  property. 

Charging  Off  Depreciation. 

Regulations  45,  article  170. — A  depreciation  allowance,  in 
order  to  constitute  an  allowable  deduction  from  gross  income,  must 
be  charged  off.  The  particular  manner  in  which  it  shall  be  charged 
off  is  not  material,  except  that  the  amount  measuring  a  reasonable 
allowance  for  depreciation  must  be  deducted  directly  from  the 
book  value  of  the  assets  or,  preferably,  credited  to  a  depreciation 
reserve  account,  which  must  be  reflected  in  the  annual  balance 
sheet.  The  allowances  should  be  computed  and  charged  off  with 
express  reference  to  specific  items,  units,  or  groups  of  property, 
each  item  or  unit  being  considered  separately  or  specifically  in- 
cluded in  a  group  with  others  to  which  the  same  factors  apply. 
The  taxpayer  should  keep  such  records  as  to  each  item  or  unit  of 
depreciable  property  as  will  permit  the  ready  verification  of  the 
factors  used  in  computing  the  allowance  for  each  year  for  each 
item,  unit,  or  group. 

Closing  Depreciation  Account  as  to  Any  Item. 

Regulations  45,  article  171. — If  the  use  of  the  property  in  the 
business  is  permanently  discontinued,  although  no  sale  or  other 
disposition  of  the  property  has  been  made,  a  determination  of  any 
gain  or  loss  may  be  made ;  but  any  deduction  in  respect  of  any  loss 
thereon  must  be  disclosed  in  the  taxpayer's  return  for  the  year  in 
which  the  determination  is  made,  and  a  full  statement  of  the  facts 
and  the  basis  upon  which  the  computation  is  calculated,  must  be 


MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY  17 

attached  to  the  return.  Upon  a  sale  or  other  disposition  of  the 
property,  the  consideration  received  shall  be  compared  with  the 
amount  of  the  estimated  salvage  value  used  in  computing  the  gain 
or  loss  as  above  provided,  and  the  amount  of  the  difference  shall 
be  treated  as  a  gain  or  loss,  as  the  case  may  be,  of  the  year  in  which 
the  sale  or  other  disposition  was  made. 

Depreciation  of  Improvements  in  the  Case  of  Oil  and  Gas  Wells. 

Regulations  45,  article  225. — Both  owners  and  lessees  operating 
oil  and  gas  properties  will,  in  addition  to  and  apart  from  the 
deduction  allowable  for  the  depletion  and  return  of  capital  as 
provided,  be  permitted  to  deduct  a  reasonable  allowance  for 
depreciation  of  physical  property,  such  as  machinery,  tools,  equip- 
ment, pipes,  etc.,  so  far  as  not  in  conflict  with  the  option  exercised 
by  the  taxpayer  under  article  223.  The  amount  deductible  on  this 
account  shall  be  such  an  amount  based  upon  its  capitalized  value 
or  cost  equitably  distributed  over  its  useful  life  as  will  bring  such 
property  to  its  true  salvage  value  when  no  longer  useful  for  the 
purpose  for  which  such  property  was  acquired.  Accordingly, 
where  it  can  be  shown  to  the  satisfaction  of  the  Commissioner  that 
the  reasonable  expectation  of  the  economic  life  of  the  oil  or  gas 
deposit  with  which  the  property  is  connected  is  shorter  than  the 
normal  useful  life  of  the  physical  property,  the  amount  annually 
deductible  for  depreciation  may  for  such  property  be  based  upon 
the  length  of  life  of  the  deposit.     See  article  161  et  seq. 

Depletion  and  Depreciation  of  Oil  and  Gas  Wells  in  Years  before 

1916. 

Regulations  45,  article  226. — If  upon  examination  it  is  found 
that  in  respect  of  the  entire  drilling  cost  of  the  wells,  including 
physical  property  and  incidental  expenses,  between  March  1,  1913, 
and  December  31,  1915,  a  taxpayer  has  been  allowed  a  reasonable 
deduction  sufficient  to  provide  for  the  elements  of  exhaustion, 
wear  and  tear,  and  depiction,  it  will  not  be  necessary  to  reopen  the 
returns  for  years  prior  to  191G  in  order  to  show  separately  in  these 
years  the  portions  of  such  deduction  representing  depletion  and 
depreciation,  respectively.  Such  separation  will  be  required  to  be 
made  of  the  reserves  for  depreciation  at  January  1,  1916,  and 


18  MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY 

proper  allocation  between  depreciation  and  depletion  must  be 
maintained  after  that  date.  In  any  case  in  which  it  is  found  that 
the  deductions  taken  between  March  1,  1913,  and  December  31j 
1915,  are  not  reasonable,  amended  returns  may  be  required  for 
these  years. 

See  Part  II. 

In  general,  taxpayers  claiming  depreciation  deductions  will  be 
required  to  submit  the  information  called  for  in  Schedule  V,  page 
62. 

AMORTIZATION. 

The  Revenue  Act  of  1918,  section  214  (a)  states  that  in  com- 
puting net  income  there  shall  be  allowed  as  a  deduction : 

(9)  In  the  case  of  builidngs,  machinery,  equipment  and  other  facihtics 
constructed,  erected,  installed,  or  acquired  on  or  after  April  6,  1917,  for  the 
production  of  articles  contributing  to  the  prosecution  of  the  present  war, 
and  in  the  case  of  vessels  constructed  or  acquired  on  or  after  such  date  for 
the  transportation  of  articles  or  men  contributing  to  the  prosecution  of  the 
present  war,  there  shall  be  allowed  a  reasonable  deduction  for  the  amortiza- 
tion of  such  part  of  the  cost  of  such  facilities  or  vessels  as  has  been  borne 
by  the  taxjiayer,  but  not  again  including  any  amount  otherwise  allowed  under 
this  title  or  previous  acts  of  Congress  as  a  deduction  in  computing  net  income. 
At  any  time  within  three  years  after  the  termination  of  the  present  war  the 
Commissioner  may,  and  at  the  request  of  the  taxpayer  shall,  reexamine  the 
return,  and  if  he  then  finds  as  a  result  of  an  appraisal  or  from  other  evidence 
that  the  deduction  originally  allowed  was  incorrect  the  taxes  imposed  by  this 
title  and  by  Title  III  for  the  year  or  years  affected  shall  be  redetermined, 
and  the  amount  of  tax  due  upon  such  redetermination,  if  any,  shall  be  paid 
upon  notice  and  demand  by  the  collector,  or  the  amount  of  tax  overpaid, 
if  any,  shall  be  credited  or  refunded  to  the  taxpayer,  in  accordance  with  the 
provisions  of  section  252. 

To  determine  the  deduction  allowable  under  tliis  provision  see 
Regulations  45,  Revised,  arts.  181-188. 

DEPLETION   OF   OIL   AND   GAS  WELLS. 

Depletion  may  be  defined  as  the  loss  sustained  through  the  pro- 
gressive exhaustion  of  a  mineral  deposit. 

Depletion  allowances  are  made  in  recognition  of  the  fact  that 
oil  and  gas  deposits  are  exhaustible  and  that  each  unit  of  oil  and 
gas  removed  reduces  the  amount  recoverable,  and  hence  reduces  the 
value  of  the  property.  Act  of  1918,  section  214  (a),  states:  That 
in  computing  net  income  there  shall  be  allowed  as  deductions : 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY  19 

(10)  In  the  case  of  mines,  oil  and  gas  wells,  other  natural  deposits,  and 
timber,  a  reasonable  allowance  for  depletion  and  for  depreciation  of  improve- 
ments, according  to  the  peculiar  conditions  of  each  case,  based  upon  cost, 
including  cost  of  development  not  otherwise  deducted:  Provided,  That  in  the 
case  of  such  properties  acquired  prior  to  March  1,  1913,  the  fair  market  value 
of  the  property  (or  the  taxpayer's  interest  therein)  on  that  date  shall  be  taken 
in  lieu  of  cost  up  to  that  date:  Provided  further,  That  in  the  case  of  mines,  oU 
and  gas  wells  discovered  by  the  taxpayer  on  or  after  March  1,  1913,  and  not 
acquired  as  the  result  of  purchase  of  a  proven  tract  or  lease,  where  the  fair 
market  value  of  the  property  is  materiallj'  disproportionate  to  the  cost  of  the 
depletion  allowance  shall  be  based  upon  the  fair  market  value  of  the  property 
at  the  date  of  the  discovery,  or  within  30  days  thereafter;  such  reasonable 
allowance  in  all  the  above  cases  to  be  made  under  rules  and  regulations  to  be 
prescribed  by  the  commissioner,  with  the  approval  of  the  Secretary.  In 
the  case  of  leases  the  deductions  allowed  by  this  paragraph  shall  be  equitably 
apportioned  between  the  lessor  and  lessee.  .  .  . 

A  reasonable  deduction  for  depletion  of  natural  deposits  and  for 
depreciation  of  improvevients  is  permitted,  based — 

(a)  Upon  cost,  if  acquired  after  February  28,  1913 ;  or 

(6)  Upon  the  fair  market  value  as  of  March  1,  1913,  if  acquired 
prior  thereto;  or 

(c)  Upon  the  fair  market  value  within  30  days  of  discovery  in 
the  case  of  mines,  oil  and  gas  wells,  discovered  by  the  taxpaj^er 
after  February  28,  1913,  where  the  fair  market  value  is  dispro- 
portionate to  the  cost. 

The  essence  of  this  provision  is  that  the  owner  of  such  property, 
whether  it  be  leasehold  or  freehold,  shall  secure  through  an  aggre- 
gate of  annual  depletion  and  depreciation  deductions  the  amount 
indicated  in  (a),  (6),  or  (c),  whicheve  ■  applies  to  his  particular 
case,  plus  in  any  case  the  subsequent  cost  of  plant  and  equipment 
(less  salvage  value)  and  underground  and  overground  develop- 
ment, which  is  not  chargeable  to  current  operating  expense,  but 
not  including  land  values  for  purposes  other  than  the  extraction 
of  minerals.  Operating  owners,  lessors,  and  lessees  are  entitled^ 
to  deduct  an  allowance  for  depletion,  but  a  stockholder  in  a  mining 
or  oil  or  gas  corporation  is  not. 

It  should  be  noted  thai  in  this  and  following  paragraphs  the 
privilege  of  revaluation  within  30  days  of  discovery  applies  to  the  dis- 
coverer solely.  No  revaluation  after  March  1,  1913,  is  allowed 
where  the  value  of  property  is  enhanced  by  discovery  made  by  any 
other  than  the  taxpayer. 


20  MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY 

ys   Capital  Recoverable    through    Depletion  Allowance  in  Case  of  an 

Owner. 

In  the  case  of  operating  owner  in  fee  or  lessor  the  capital 
recoverable  through  depletion  allowances  consists  in — 

(a)  Cost  of  the  property,  or  its  fair  market  value  as  of  March  1, 
1913,  if  acquired  prior  thereto,  or  its  fair  market  value  within  30 
days  of  discovery,  as  the  case  may  be ;  plus 

(6)  Cost  of  subsequent  unprovements  and  development  not 
charged  to  current  operating  expenses;  minus 

(c)  Deductions  for  depletion  which  have  or  should  have  been 
taken  to  date ;  and  minus 

(d)  The  portion  of  the  capital  sum  as  to  which  depreciation 
instead  of  depletion  has  been  and  is  being  deducted. 

The  cost  or  value  stated  under  (a)  does  not  include  the  value  of 
the  land  other  than  as  the  container  of  oil  and  gas.  Depletion 
may  be  claimed  against  that  portion  of  the  cost  or  value  which 
resides  in  the  mineral  deposit  which  is  being  exploited.  To  ob- 
tain this  it  is  necessary  to  deduct  from  total  cost  or  value  the  cost 
or  value  of  the  property  other  than  as  a  container  of  oil  and  gas. 

Obviously,  the  lessor  may  not  include  in  his  capital  sum  any 
part  of  the  discovery  value  or  any  part  of  the  sums  expended  by  the 
lessee  in  the  development  of  the  property,  as  mentioned  under 
(6),  and  the  operating  owner  in  fee  may  include  only  such  costs  or 
values  as  have  not  been  deducted  as  current  operating  expense  or 
otherwise. 

Where  depletion  deductions  for  former  years  have  or  should 
have  been  taken,  these  amounts  are  to  be  subtracted  from  the 
capital  sum  returnable  through  depletion  deductions. 

In  no  case  shall  the  account  returnable  through  deductions  for 
depletion  include  items  against  which  depreciation  is  l)cing  charged ; 
that  is,  the  cost  (or  value)  of  physical  property  may  not  be  in- 
cluded, since  it  is  returnable  through  depreciation  deductions. 

Capital   Recoverable   through    Depletion   Allowances   in   the    Case 

of  Lessee. 

Regulations  45,  article  203. — In  the  case  of  the  lessee  the  capital 
remaining  in  any  year  recoverable  through  depletion  allowances  is 
the  sum  of 

(a)  The  cost  of  the  leasehold,  or  its  fair  market  value  as  of 


MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY  21 

March  1,  1913,  or  its  fair  market  value  within  30  days  after  dis- 
covery; phis 

(6)  The  cost  of  subsequent  improvements  and  development 
not  charged  to  current  operating  expenses,  but  minus 

(c)  Deductions  for  depletion  which  have  or  should  have  been 
taken  to  date,  and 

(d)  The  portion  of  the  capital  sum,  if  any,  as  to  which  depre- 
ciation instead  of  depletion  should  be  charged. 

Bonuses  constitute  a  part  of  the  cost  of  the  leasehold.  (See 
cost  of  property,  p.  9.)  Any  annual  or  period  cal  rents  or  flat 
royalties  (as  in  the  case  of  gas  wells)  supplementing  the  bonuses  or 
other  amount  paid  for  the  lease  at  the  time  of  acquisitioji  may  be 
charged  to  cost  of  leasehold  until  the  property  reaches  the  operat- 
ing stage  and  will  form  part  of  the  capital  returnable  through 
deductions  for  depletion. 

Illustration 

A's  invested  capital  in  a  leasehold  on  March  1,  1913,  was 
$200,000. 

His  estimated  oil  reserves  on  that  date  were  2,000,000  barrels. 

Under  the  Act  of  1913,  the  lessee  was  not  allowed  a  revaluation 
for  purposes  of  computing  his  depletion  deduction  from  gross  in- 
come. And  the  depletion  taken  could  not  exceed  5  per  cent  of  the 
value  of  the  oil  at  the  well. 

' ,  or  10  cents,  represents  the  unit  cost  of  each  barrel 

2,000,000' 

of  oil  in  the  property  at  that  date. 

He  extracts  and  sells — 

200,000  barrels  in  1913  for $100,000 

150,000  barrels  in  1914  for 90,000 

125,000  barrels  in  1915  for 60,000 

100,000  barrels  in  191C)  for 50,000 

75,000  barrels  in  1917  fur •     100,000 

He  has  sold  050,000  barrels  for $100,000 

Deplotinn  Doplction 

SustaiiuHl.  Allowod. 

1913 $20,000  $5,000 

1914^ ' '  ' '  " 15,000  4,500 

1915 12,500  3,000 

1916.  '  ' 10,000  10,000 

1917^^^ 7,500      7,.500 

Total ■ $65,000         $30,000 


22  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

For  purposes  of  taxation  in  1918  A's  invested  capital  is  $200,- 
000- 65,000  =  $135,000  and  not  $200,000 -30,000  =  $170,000. 

The  Revenue  Act  of  1918  allows  A  to  revalue  his  property  as 
of  March  1,  1913.  The  valuation  ("Capital  Sum")  claimed  by  A 
and  allowed  by  the  Commissioner  was  $1,000,000. 

The  unit  cost  for  purposes  of  computing  depletion  deductions 

,    .    $1,000,000        ^„  _„         ,         , 
from  capital  assets  is      '       '       ,  or  $0.50  per  barrel. 

Zi  J  UUU  J  \j\J\J 

The  total  depletion  of  capital  sum  to  January  1,  1918,  was, 
therefore,  650,000  X  $0.50  =  $325,000. 

Capital  sum  at  January  1,  1918,  is,  therefore,  $1,000,000  — 
$325,000,  or  $675,000,  and  not  $1,000,000 -$30,000,  or  $970,000. 

A  pportionment  of  Deductions  between  Lessor  and  Lessee. 

Regulations  45,  article  204. — As  the  value  of  the  property  com- 
prehends the  interests  of  both  lessor  and  lessee,  no  computation 
for  the  purpose  of  depletion  allowances,  of  the  value  of  these 
interests  separately  as  of  any  date  which  combined  exceeds  the 
value  of  the  property  in  fee  simple  will  be  permitted.  The  same 
principle  apples  to  holders  of  fractional  interests.  If  the  agree- 
gate  deduction  claimed  is  deemed  excessive,  the  Commissioner  may 
request  the  owner  or  lessee  to  show  that  the  valuation  claimed  does 
not  exceed  the  fair  market  value  of  the  property  at  a  specified 
date  determined  in  the  manner  explained  in  Regulations  45, 
article  206.  The  lessor  and  lessee  shall,  with  the  approval  of  the 
Commissioner,  equitably  apportion  the  allowance  in  the  light  of 
the  peculiar  conditions  in  each  case  and  on  the  basis  of  their 
respective  interests  therein.  To  the  return  of  every  taxpayer 
claiming  an  allowance  for  depletion  in  respect  of  (a)  a  property  in 
which  he  owns  a  fractional  interest  only,  or  (h)  a  leasehold,  or  (c) 
a  property  subject  to  a  lease,  there  shall  be  attached  a  statement 
setting  forth  the  name  and  address  and  the  precise  nature  of  the 
holdings  of  each  person  interested  in  the  property. 

In  the  case  of  the  lessor,  the  depletion  deduction  is  computed 
like  that  of  the  operating  owner,  except  that  ordinarily  the  only 
amount  of  capital  to  be  returned  is  the  cost  of  the  oil  or  gas  deposit 
if  acquired  subsequent  to  March  1,  1913,  or  its  fair  market  value 
en  bloc  as  of  March  1,  1913,  if  acquired  prior  thereto,  or  within  30 
days  of  discovery  of  oil  or  gas  wells  if  discovered  by  the  taxpayer. 


MANUAL  FOR  THE  OIL  AND   GAS  INDUSTRY  23 

The  value  of  the  land  for  purposes  other  than  as  a  container  of  oil 
or  gas  must  always  be  deducted  from  the  cost  or  value  above  to 
obtain  the  cost  or  value  of  the  oil  or  gas  deposits. 

Such  cost  or  value  divided  by  the  estimated  units  of  oil  or  gas 
in  the  ground  on  the  date  of  acquisition  or  valuation  will  give  the 
unit  cost  or  value  to  be  applied  against  the  number  of  units  re- 
moved from  the  lessor's  property  by  the  lessee,  irrespective  of  the 
amount  of  oil  received  by  the  lessor  as  royalty.  However,  in 
cases  where  the  property  was  leased  before  JMarch  1,  1913,  at  a 
fixed  price  'per  unit,  instead  of  a  royalty  payable  in  kind  the  lessor 
would  be  restricted  by  the  valuation  indicated  by  such  fixed  price, 
as  fluctuations  in  the  market  value  of  oil  subsequent  to  the  lease 
would  affect  the  valuation  of  the  lessee  only. 

DETERMINATION  OF  COSTS  OF  DEPOSITS. 

Regulations  45,  article  205.— In  any  case  in  which  a  depletion 
or  depreciation  deduction  is  computed  on  the  basis  of  the  cost  or 
price  at  which  any  mine,  mineral  deposit,  mineral  rights,  or  lease- 
hold was  acquired,  the  owner  or  lessee  will  be  required  upon  request 
of  the  Commissioner  to  show  that  the  cost  or  price  at  which  the 
property  was  bought  was  fixed  for  the  purpose  of  a  bona  fide 
purchase  and  sale,  by  which  the  property  passed  to  an  owner,  in 
fact  as  well  as  in  form,  different  from  the  vendor. 

No  fictitious  or  inflated  cost  or  price  will  be  permitted  to  form 
the  basis  of  any  calculation  of  a  depletion  or  depreciation  deduc- 
tion, and  in  determining  whether  or  not  the  price  or  cost  at  which 
any  purchase  or  sale  was  made  represented  the  actual  market 
value  of  the  property  sold,  due  weight  will  be  given  to  the  relation- 
ship or  connection  existing  between  the  person  seUing  the  property 
and  the  buyer  thereof. 

In  general,  the  taxpayer  will  be  required  to  submit  the  informa- 
tion called  for  in  Schedule  I,  page  47. 

DETERMINATION  OF  FAIR  MARKET  VALUE. 

Introductory  Statement. 

A  determination  of  the  fair  market  value  of  an  oil  or  gas  prop- 
erty (or  the  taxpayer's  interest  therein)  is  required : 

(a)  In  connection  with  the  computation  of  dei)letion  allow- 
ances : 


24  MANUAL  FOR  THE   OIL  AND   GAS  INDUSTRY 

(1)  As  of  March  1,  1913,  in  the  case  of  properties  acquired 
prior  to  that  date;  and 

(2)  At  the  date  of  discovery  or  within  30  days  thm'eafter  in 
the  case  of  oil  and  gas  wells,  discovered  by  the  taxpayer  on  or 
after  March  1,  1913,  and  not  acquired  as  the  result  of  purchase 
of  a  proven  tract  or  lease  where  the  fair  market  value  of  the 
property  is  disproportionate  to  the  cost. 

(6)  In  connection  with  computing  the  amount  which  may  be 
included  in  paid-in  surplus,  as  of  date  of  conveyance,  where  the  tan- 
gible property  has  been  conveyed  to  a  corporation  by  gift  or  at  a 
value  accurately  established  or  definitely  known  as  at  date  of  con- 
veyance clearly  and  substantially  in  excess  of  the  cash  or  of  the 
par  value  of  the  stock  or  shares  paid  therefor. 

(c)  In  connection  with  the  computation  of  profit  and  loss  from 
sale  of  capita^,  assets  in  the  case  of  properties  acquired  prior  to 
March  1,  1913. 

Regulations  45,  article  206. — Where  the  fair  market  value  of 
the  property  at  a  specified  date  in  lieu  of  the  cost  thereof  is  the 
basis  for  depletion  and  depreciation  deductions,  such  value  must 
be  determined,  subject  to  approval  or  revision  by  the  Commis- 
sioner, by  the  owner  of  the  property  in  the  light  of  the  conditions 
and  circumstances  known  at  that  date,  regardless  of  later  dis- 
coveries or  developments  in  the  property  or  in  methods  of  mining 
or  extraction. 

The  value  sought  should  be  that  established  assuming  a  transfer 
between  a  wilhng  seller  and  a  willing  buyer  as  of  that  particular 
date. 

No  rule  or  method  of  determining  the  fair  market  value  of 
mineral  property  is  prescribed,  but  the  Commissioner  will  lend  due 
weight  and  consideration  to  any  or  all  factors  and  evidence  having 
a  bearing  on  the  market  value,  such  as  (a)  cost,  (6)  actual  sales  and 
transfers  of  similar  properties,  (c)  market  value  of  stock  or  shares, 
(d)  royalties  and  rentals,  (e)  value  fixed  by  the  owner  for  the  pur- 
poses of  the  capital-stock  tax,  (/)  valuation  for  local  or  State 
taxation,  (g)  partnership  accountings,  (h)  records  of  litigation  in 
which  the  value  of  the  property  was  in  question,  (z)  the  amount 
at  which  the  property  may  have  been  inventoried  in  probate  court, 
(j)  disinterested  appraisal  by  approved  methods,  and  (k)  other 
factors. 


MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY  25 

In  order  to  meet  the  requirements  of  the  case  to  the  satisfaction 
of  the  Commissioner  the  taxpayer  will  be  required  to  submit  the 
information  called  for  in  Schedule  II.  See  also  Proof  of  Dis- 
covery, page  45. 

Ruling  Regarding  Valuation. 

Valuation  of  fee  under  lease. — The  valuation  of  a  fee  owner- 
ship in  oil  or  gas  land  under  lease  acquired  prior  to  March  1,  1913, 
will  have  to  do  with  the  equity  in  its  oil  and  gas  contents  remain- 
ing to  the  owner  of  the  fee  title  after  deducting  the  value  of  the 
lessee's  rights.  But  subsequent  investments  or  discoveries  by  the 
lessee  will  not  affect  the  lessor's  valuation. 

No  Revaluation  of  Property  Permitted. 

Regulations  45,  article  207. — The  cost  of  the  property  or  its 
fair  market  value  at  a  specified  date,  as  the  case  jnay  be,  plus 
subsequent  charges  to  capital  sum  not  deductible  as  current  ex- 
penses, will  be  the  basis  for  determining  the  depletion  and  depre- 
ciation deductions  for  each  year  during  the  continuance  of  the 
ownership  under  which  the  fair  market  value  or  cost  was  fixed, 
and  durng  such  ownership  there  can  be  no  revaluation  for  the 
purpose  of  this  deductoin.  This  rule  will  not  forbid  the  redis- 
tribution of  the  capital  sum  over  the  estimated  number  of  units 
remaining  in  the  property  in  accordance  with  either  of  the  next  two 
articles. 

Determination  of  Quantity  of  Oil  in  Ground. 

Regulations  45,  article  209. — In  the  case  of  either  an  owner  or 
lessee  it  will  be  required  that  an  estimate,  subject  to  the  approval 
of  the  Commissioner,  shall  be  made  of  the  probable  recoverable  oil 
contained  in  the  territory  with  respect  to  which  the  investment  is 
made  as  of  the  time  of  purchase,  or  as  of  March  1,  1913,  if  acquired 
prior  to  that  date,  or  within  30  daj^s  after  the  date  of  discovery,  as 
the  case  may  be.  The  oil  reserves  must  })e  esthnated  for  all  untlc- 
veloped  proven  land  as  well  as  producing  land.  If  information 
subsequently  obtained  clearly  shows  the  estimate  to  have  been 
materially  erroneous,  it  may  be  revised  with  the  approval  of  the 
Connnissioner, 


26  MANUAL  FOR  THE   OIL   AND   GAS   INDUSTRY 

The  estimate  of  probable  recoverable  oil  in  the  ground  is  funda- 
mentally necessary  if  a  reasonable  deduction  for  depletion  is  to  be 
calculated,  and,  while  it  may  be  impossible  to  determine  exactly 
the  future  production  of  a  well  or  tract,  it  has  been  found  possible 
to  predict  future  productions  with  a  comparatively  narrow  limit 
of  error.  The  result  of  analysis  of  a  great  volume  of  production 
records  ha?  led  to  the  development  of  the  methods  auggested  in 
Part  III  of  the  Manual. 

Methods  of  Estimating  Recoverable  Reserves. 

The  Treasury  Department  does  not  prescribe  any  particular 
method  of  estimating  recoverable  reserves,  but  the  methods 
described  in  Part  IV  of  the  Manual  are  applicable  to  a  wide  variety 
of  conditions  and  are  inserted  as  a  suggestion. 

The  underlying  principle  of  the  methods  outlined  i^  that  the 
best  indication  of  the  future  production  of  any  well  ts  to  be  found  in 
the  history  of  similar  wells  in  the  same  or  similar  districts,  and  that, 
other  things  being  equal,  a  well's  production  is  more  likely  to  ap- 
proxima'e  the  production  of  a  similar  well  in  the  tract  or  district 
than  to  deviate  widely  from  the  average. 

The  method  may  be  sunmiarized  as  follows: 

1.  Plotting  the  record  of  production  of  individual  wells,  or, 
lacking  such  detailed  information,  the  average  production  per  well 
for  each  tract. 

2.  Deriving  from  these  graphical  records  an  average  or  com- 
posite production  decline  curve  for  the  district. 

3.  Estimating  from  the  last  year's  average  production  per  well 
the  probable  future  production,  based  on  the  average  production 
decline  curve,  or  a  future  production  curve  derived  from  the  pro- 
duction decline  curve 

4.  Ascertaining  probable  total  future  production  of  producing 
wells  by  multiplying  average  future  production  per  well  by  the 
number  of  wells  producing  at  the  end  of  the  year. 

5.  Estimating  the  probable  future  production  of  undeveloped 
proven  land  on  the  basis  of  near-by  production,  making  due  allow- 
ance for  the  decline  in  pressure  due  to  the  extraction  of  oil  from  the 
pool. 

It  is  to  be  emphasized  that  the  value  of  estimates  will  depend 
aimost  entirely  upon  the  skill  with  which  the  method  is  carried 


MANUAL  FOR  THE  OIL  AND   GAS  INDUSTRY  27 

out  and  the  character  of  the  production  records  upon  which  they 
are  based.  Where  accurate  detailed  records  are  not  kept,  it  ma}^  be 
difficult  to  determine  a  "reasonable  allowance  for  depletion." 

The  taxpayer  may  estimate  his  recoverable  reserves  by  any 
method  that  can  be  shown  to  be  well  founded,  but  in  all  cases  the 
data  upon  which  such  estimate  was  based  must  be  submitted  with 
a  description  of  the  method  employed,  and  a  resume  of  the  cal- 
culations. 

COMPUTATION  OF  ALLOWANCE  FOR  DEPLETION  OF  OIL  WELLS. 

Regulations  45,  article  210. — When  the  cost  or  value  as  of 
March  1,  1913,  or  within  30  days  after  the  date  of  discovery  of  the 
property,  shall  have  been  determined,  and  the  number  of  mineral 
units  in  the  property  as  of  the  date  of  acquisition  or  valuation  shall 
have  been  estimated,  the  division  of  the  former  amount  by  the 
latter  figure  will  give  the  unit  value  for  the  purpos^esj)f  depletion, 
and  the  depletion  allowance  for  the  taxable  year  may  be  computed 
by  multiplying  such  unit  value  by  the  number  of  units  of  mineral 
extracted  during  the  year.  If,  however,  proper  additions  are  made 
to  the  capital  account  represented  by  the  original  cost  or  value  of 
the  property,  or  circumstances  make  advisable  a  revised  estimate 
of  the  number  of  mineral  units  in  the  ground,  a  new  unit  value  for 
purposes  of  depletion  may  be  found  by  dividing  the  capital  account 
at  the  end  of  the  year,  less  deductions  for  depletion  to  the  beginning 
of  the  taxable  year  which  have  or  should  have  been  taken,  by  the 
number  of  units  in  the  ground  at  the  beginning  of  the  taxable 
year.  This  number,  unless  a  revision  of  the  original  estimate  has 
been  made,  will  equal  the  number  of  units  in  the  ground  at  the 
date  of  original  acquisition  or  valuation  less  the  number  extracted 
prior  to  the  taxable  year.  If,  however,  a  recalculation  is  made, 
the  number  of  units  at  the  beginning  of  the  year  will  be  the  sum  of 
the  gross  production  of  the  year  and  the  estimated  mineral  re- 
serves in  the  property  at  the  end  of  the  j^ear. 

Each  barrel  of  oil  or  unit  of  gas  extracted  and  marketed  niust, 
before  a  profit  can  be  realized,  pay  not  only  its  proi)ortionate  share 
of  the  operating  expense  and  deductions  for  depreciation  and  obso- 
lescence of  physical  property,  but  also  must  pay  its  proportionate 
share  of  capital  sum  returnable  through  depletion  allowances. 
(See  above.) 

This  proportionate  share  of  capital  suni  retm-nable  through 


28  MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY 

depletion  allowances,  which  each  unit  of  oil  or  gas  must  pay,  is  unit 
cost. 

Unit  cost  is  obtained  by  dividing  the  capital  sum  returnable 
through  depletion  bj^  the  "estimated  recoverable  reserve"  at  the 
beginning  of  the  taxable  year. 

The  depletion  deduction  is  computed  by  multiplying  the  unit 
cost  by  the  number  of  units  produced  during  he  taxable  year. 

It  is  to  be  noted  that  the  estimated  recoverable  reserves  and  the 
number  of  units  produced  are  used  in  estimating  the  depletion 
deduction  for  both  lessor  and  lessee.  Since,  however,  they  are 
applied  to  different  capital  amounts  returnable  through  depletion 
deductions,  the  unit  costs  for  lessee  and  lessor  are  not  identical, 
and  the  deductions  bear  the  same  ratio  as  the  capital  sum  of  lessor 
and  lessee.  Usually  the  lessee's  investment  is  greater  than  the 
lessor's  and  his  deductions  are  correspondingly  greater. 

Stated  in  another  way,  if  a  certain  proportionate  part  of  the 
lessee's  capital  returnable  through  depletion  deductions  is  deducted 
in  a  given  year  the  same  proportion  of  the  lessor's  capital  sum  re- 
turnable through  depletion  will  be  deducted. 

(See  apportionment  of  deductions  between  lessor  and  lessee.) 

Illustration : 

A,  a  lessee,  has  an  oil  lease  in  which  his  original  investment  (exclu- 
sive of  value  of  physical  property)  was $20,000 

Development  cost  (exclusive  of  cost  of  physical  property)  not  other- 
wise deducted 80.000 


Capital  returnable  through  depletion  allowance $100,000 

Estimated  recoverable  reserves  at  end  of  taxable  year barrels  400.000 

Produced  during  taxable  year * '  100.000 

Estimated  oil  at  beginning  of  year "  500,000 

$100  000 

Therefore  unit  cost  is  -n^/r^TTTTK-  or  per  barrel $0  20 

500,000  ■ 

A's  depletion  allowance  for  the  taxable  year  is,  therefore  $0.20 X 

100,000,  or $20,000 

B,  the  owner  in  fee  of  the  property,  had  invested $40,000 

Of  which  the  value  of  the  land  exclusive  of  oil  rights  represents ....  25,000 


The  investment  in  the  oil  deposit  is $15,000 

B's  unit  cost,  is  therefore,  ^^^7^7,7^7;,  or  per  barrel $0  03 

500,000 

And  his  depletion  allowance  for  the  same  year  $0 .  03  X  100,000,  or .  .  $3,000 


MANUAL   FOR   THE   OIL   AND   GAS  INDUSTRY  29 

The  above  example  presupposes  that  B  leased  his  land  without 
bonus. 

Any  amount  received  by  a  lessor  as  bonus  for  an  oil  and  gas 
lease  on  the  property  would  reduce  his  capital  sum  by  that  amount. 

Illustration: 

The  lessor's  (B  ?)  investment  in  the  deposit  is $15,000 

He  receives  as  bonus     5,000 


His  net  investment  in  the  deposit  is  therefore $10,000 


He  sells  a  one  half  mterest  m  his  royalty  for $6,000 

As  this  half  cost  him  5,000 


His  profit  is $1,000 

And  is  subject  to  tax  as  income. 

His  capital  sum  remaining  is $5,000 

If  he  had  sold  a  one-half  interest  in  his  royalty  for $4,000 


He  would  have  sustained  a  loss  of $1,000 

and  should  deduct  this  amount  from  gross  income  as  a  loss  in  computing 
his  tax, 

COMPUTATIONS    OF    ALLOWANCE    FOR    DEPLETION    OF    GAS 

WELLS. 

Regulations  45,  article  211.— The  deductions  allowed  in  com- 
puting income  from  natural-gas  properties  are  in  general  similar  to 
those  allowed  oil  operators,  but  the  method  of  computing  the  de- 
ductions and  the  various  assets  differ  in  certain  particulars,  the 
most  notable  of  which  are  involved  in  the  problems  of  estimating 
the  probable  reserves  and  computing  the  depletion. 

On  account  of  the  peculiar  conditions  surrounding  the  pro- 
duction of  natural  gas  it  is  necessa  y  to  compute  the  depletion 
allowance  for  gas  properties  by  methods  suitable  to  the  particular 
cases.  Usually  the  depletion  shou'.d  be  computed  on  the  basis  of 
decline  in  closed  or  rock  pressure,  taking  into  account  the  effects  of 
water  encroachment  and  any  other  modifying  factors.  In  many 
fields  more  or  less  additional  evidence  on  depletion  is  to  be  had  from 
such  considerations  as  (a)  details  of  production  and  performance 
records  of  well  or  property,  (6)  decline  in  open  flow  capacity,  (c) 
comparison  with  the  life  histories  of  similar  wells  or  properties, 
particularly  those  now  exhausted,  and  (d)  size  of  reservoir  and 
pressure  of  gas. 


30  MANUAL  FOR  THE  OIL   AND   GAS   INDUSTRY 

METHODS  OF  COMPUTING  GAS  DEPLETION. 

Details  of  production  or  the  performance  record  of  the  well  or 
property. — As  a  general  rule  the  demand  on  a  natural  gas  property 
is  a  variable  factor.  In  certain  fields,  however,  the  demand  from 
some  wells  has  from  the  beginning,  or  for  considerable  periods,  been 
greater  than  the  supply,  so  that  the  amount  of  gas  marketed  per 
well  may,  as  in  the  case  of  oil,  show  a  regular  decline,  which  will  be 
indicative  of  the  total  amount  that  the  well  may  be  expected  to 
produce  and  also  the  rate  of  production.  Even  where  the  demand 
does  not  greatly  exceed  the  supply,  the  amount  and  rate  of  past 
production  may  in  certain  cases  throw  light  on  the  future  of  the 
well  or  property. 

Decline  in  open-flow  capacity. — Where  data  are  available  the 
decline  in  open-flow  capacity  indicates  in  a  general  way  the  rate  of 
exhaustion  of  the  gas  field.  The  relationship  is  not  at  all  close 
and  varies  from  field  to  field  and  from  well  to  well.  Also  for  most 
gas  wells  accurate  data  on  decline  in  open-flow  capacity  are  not 
available.  Nevertheless  it  is  probable  that  for  certain  properties 
this  method  will  have  value,  for  with  rare  exceptions  the  production 
of  gas  from  a  well  leads  to  a  decline  in  its  capacity,  and  the  fraction  - 
produced  is  roughly  proportional  to  the  decline. 

Comparison  with  life  history  of  similar  wells  or  properties, 
particularly  those  now  exhausted  or  nearing  exhaustion. — Where 
no  other  data  are  available  the  rate  of  depletion  of  a  gas  well  or 
property  may  be  approximated  by  comparison  with  a  neighboring 
well  or  property  that  has  reached  a  later  stage  in  life.  Particu- 
larly is  this  applicable  in  a  district  where  many  gas  wells  have  be- 
come exhasuted.  For  example,  in  a  region  where  wells  produce 
from  8  to  12  years,  or  an  average  of  10  years,  a  10  per  cent  deduc- 
tion will  be  a  rough  approximation  of  the  rate  of  depletion. 

Size  of  reservoir  and  pressure  of  gas,  or  the  pore-space  method, 
— For  some  properties  the  pore-space  method  may  be  best  for 
estimating  underground  supplies  of  natural  gas  and  for  a  good 
many  it  will  furnish  additional  evidence  of  value.  The  method 
would  be  ideal  if  the  average  percentage  of  pore  space,  the  extent 
and  thickness  of  the  sand,  and  the  pressure  of  the  gas  could  be 
accurately  ascertained.  In  computing  the  reserves  of  an  individual 
property  by  this  method  the  migratoiy  character  of  gas  must  be 
considered  and  the  production  and  behavior  of  adjacent  properties 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY  31 

taken  into  account.  The  factors  that  make  the  niethod  difficult 
to  apply  are  difficulty  of  accurately  ascertaining  the  thickness  of 
pay,  limits  of  pool,  percentage  of  pore  space,  the  effect  of  encroach- 
ing water  and  oil,  and  the  quantity  of  gas  remaining  when  com- 
mercial production  is  no  longer  possible. 

Take,  for  example,  a  pool  where  there  is  no  encroachment  by 
water.  Suppose  that  the  pore  space  is  25  per  cent,  the  thickness 
of  the  pay  20  feet,  and  the  extent  of  the  pool  10  square  miles,  or 
roughly  280,000,000  square  feet.  The  volume  of  the  reservoir 
would  be  1,400,000,000  cubic  feet,  and  the  amount  of  gas  in  the 
sand  could  be  readily  computed  by  taking  into  account  the  closed 
pressure  of  the  wells. 

Other  indications  of  depletion. — Additional  evidence  of  de- 
creasing supply  of  natural  gas  in  the  ground  is  commonly  observ- 
able in  the  behavior  of  the  wells  and  the  provision  that  must  be 
made  for  transporting  the  gas  to  market.  Observations  on 
minute  pressures  show  more  or  less  progressive  change  as  the  wells 
become  older  and  an  increasing  amount  of  gas  is  drawn  from  the 
ground.  Line  pressures  and  pressures  at  compressing  stations  are 
also  likely  to  show  a  progressive  change  in  the  same  direction. 
The  appearance  of  water  or  oil  in  a  gas  well  or  in  neighboring  gas 
wells  may  be  a  very  significant  symptom  of  the  approaching  termi- 
nation of  the  life  of  the  well.  The  clogging  of  gas  wells  by  par- 
affin, salt,  or  other  deposits  may  demand  modification  of  depletion 
estimates. 

CLOSED-PRESSURE  METHOD. 

Because  of  its  general  applicability,  the  closed-pressure  method 
is  by  far  the  best  method  of  estimating  the  depletion  of  gas  prop- 
erties. 

Unfortunately,  accurate  closed-pressure  data  have  not  been 
kept  for  all  properties  or  perhaps  even  for  the  majority  of  proper- 
ties, but  the  rock  pressure  in  most  pools  is  known  or  is  ascertainable 
with  a  fair  degree  of  accuracy,  and  the  information  drawn  from  the 
pressure  decline  is,  with  the  exception  of  a  few  fields,  not  subject 
to  profound  modification,  because  of  factors  whose  value  can  not  be 
appraised.  The  basis  of  this  method  is  Boyle's  law.  According  to 
this  law  of  physics,  if  gas  is  pumped  into  a  vessel  until  the  pressure 
is  200  pounds  and  then  is  drawn  off  until  the  pressure  is  100  pounds, 
the  size  of  the  vessel  remaining  fixed,  and  ignoring  for  the  nioment 


32  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

atmospheric  pressure,  it  may  be  concluded  that  one-half  of  the  gas 
has  been  drawn  out  of  the  vessel.  If  an  underground  gas  reservoir 
of  fixed  dimensions  is  tapped  by  wells  and  the  pressure  is  found  to 
be  a  thousand  pounds,  and  then  if  the  gas  is  drawn  off  through  the 
wells  until  the  gas  pressure  in  the  pool  is  lowered  to  100  pounds,  we 
may  infer  that  about  nine-tenths  of  the  supply  of  gas  has  been 
exhausted. 

"Unit  cost"  as  applied  to  natural  gas. — Although,  as  a  rule,  the 
number  of  cubic  feet  of  gas  under  a  tract  can  not  be  satisfactorily 
estimated  and  the  quantity  that  will  be  marketed  is  even  less 
definite,  the  ''unit  cost  method"  can  be  used  by  regarding  pounds 
of  closed  pressure  as  units,  for  the  actual  quantity  of  gas  under- 
ground commonly  varies  with  the  decline  in  pressure  and  the 
relative  quantity  at  the  beginning  and  end  of  the  tax  year  and  at 
the  time  of  abandonment,  is,  in  the  lack  of  better  information, 
usable  for  tax  purposes. 

Corrections  and  refinements  of  closed-pressure  me.hod. — 
Several  corrections  and  more  or  less  important  refinements  are 
made  in  applying  this  method  to  the  computation  of  depletion, 
and  it  should  be  borne  in  mind  that  it  does  not  afford  data  on  the 
amount  of  gas  originally  in  the  pool  or  at  any  later  specified  time, 
but  only  the  fraction  of  the  gas  that  has  been  removed  from  its 
natural  reservoir  and  the  fraction  remaining  in  that  reservoir. 
Perhaps  the  most  important  of  these  corrections  arises  out  of  the 
fact  that  the  size  of  the  reservoir  does  not  remain  fixed  but  be- 
comes smaller  as  the  gas  is  drawn  and  water  or  oil  advances  into  a 
part  of  the  space  formerly  occupied  by  the  gas.  The  pressure  is 
thus  prevented  from  declining  at  a  rate  proportionate  to  the 
amount  of  gas  drawn  from  the  pool.  The  correction  on  account 
of  water  or  oil  encroachment  is  difficult  to  make,  because  of  the 
lack  of  data  to  determine  the  extent  of  the  encroachment.  How- 
ever, in  a  good  many  pools,  after  a  study  of  the  distribution  of 
wells  that  have  been  "drowned  out"  and  the  history  of  water 
troubles  in  similar  near-by  pools,  it  is  possible  to  make  allow- 
ance for  water  or  oil  encroachment  which  will  more  or  less  closely 
approximate  the  facts. 

Another  refinement  applicable  to  the  computation  of  depletion 
of  natural  gas  by  the  closed-pressure  method  is  based  upon  the 
fact  that  even  where  there  is  no  encroachment  of  water  or  oil  the 
depletion  is  not  precisely  represented  by  the  gauge  readings, 


MANUAL  FOR  THE   OIL  AND   GAS  INDUSTRY  33 

though  the  errors  are  generally  so  small  that  they  may  be  ignored. 
For  example,  where  the  pressure  declines  from  1,000  to  500  pounds, 
the  gas  is  not  exactly  half  gone,  for  the  reason  the  pressures  referred 
to  are  guage  readings  and  to  each  should  be  added  the  pressure  of 
the  atmosphere — for  most  fields  about  14.4  points  to  the  square 
inch.     The  fraction  remaining  in  the  ground  then  becomes  ioT4.4- 

Account  should  also  be  taken  of  the  pressure  at  which  wells 
are  abandoned  in  the  field  or  district. 

If  wells  can  not  be  operated  with  profit  after  the  pressure  has 
declined  to  25  pounds  gauge  reading  (39.4  pounds  absolute),  then 
the  percentage  of  recoverable  gas  remaining  when  the  pressure  has 
declined  from  1,000  to  500  pounds  gauge  reading  is  not  one-half  or 
even  the  fraction  joio  but  gyf.  The  difference  in  the  fraction 
where  pressures  of  several  hundred  pounds  are  involved  is  not  great 
and  scarcely  worth  considering  in  view  of  the  other  errors  wliich 
are  certain  to  affect  the  result.  However,  after  the  pressure  has 
declined  to  a  low  figure,  the  matter  of  correcting  the  fraction 
becomes  of  considerable  importance.  Thus,  if  the  pressure  of 
abandonment  is  4  pounds  guage  reading  and  during  the  year  the 
average  closed  pressure  of  a  pool  has  declined  from  10  pounds  to  5 
pounds  gauge  reading,  five-sixths  instead  of  one-half  of  the  recover- 
able gas  has  been  withdrawn. 

Still  another  refinement  that  has,  as  a  rule,  more  theoretical 
than  practical  value  may  be  worthy  of  consideration  in  certain 
instances.  This  arises  out  of  the  fact  the  gases  do  not  expand 
precisely  as  the  pressure  decreases,  and  that  even  i'  the  size  of  the 
natural  reservoir  remains  fixed  the  pressure  does  not  decline  in 
exact  proportion  to  the  amount  of  gas  removed.  The  difference 
amounts  to  only  a  few  per  cent  and  is  greatest  for  liigh  pressures. 
In  the  decline  from  1,000  to  500  pounds  per  square  inch  the  gas 
expands  several  per  cent  more  than  would  be  calculated  by  a  strict 
application  of  Boyle's  law,  and  in  a  decline  from  1,500  pounds  to 
1,000  pounds  the  departure  is  still  greater.  The  correction  varies 
from  field  to  field  because  of  the  different  constitution  of  the  gases, 
though  since  most  natural  gases  consist  largely  of  methane  the 
variations  on  account  of  differences  in  gases  are  not  great. 

A  fourth  detail  of  refinement  arises  out  of  the  fact  that  on  the 
average  more  gas  is  marketed  for  50  pounds  of  decline  in  pressure 
after  the  pressure  has  reached  100  pounds  or  less  than  an  equal 
decline  while  the  pressure  is  high,  as,  for  example,  1,000  pounds 


34  MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY 

per  square  inch.  Also  the  expense  of  marketing  gas  after  the 
pressure  has  become  low  is  greater  than  when  it  was  high,  largely 
because  of  the  necessity  of  installing  compressors  to  push  the  gas 
through  the  pipe  lines  to  the  consumers.  These  two  considera- 
tions have  a  tendency  to  balance  each  other  and,  with  certain  ex- 
ceptions, will  not  be  of  sufficient  importance  to  warrant  an  attempt 
to  apply  the  corrections. 

METHOD  OF  GAUGING. 

In  using  the  closed-pressure  method  of  estimating  depletion, 
the  method  of  gauging  is  of  vital  importance  and  in  many  fields  is 
not  carried  out  with  sufficient  care.  Care  should  be  taken  to  make 
sure  that  the  gauge  is  accurate,  testing  it  before  and  after  attach- 
ing it  to  the  well.  If  it  must  be  transported  far  or  is  subject  to 
much  jolting  in  transportation,  a  gauge  tester  should  be  taken 
along  and  used  at  the  well. 

Care  should  also  be  taken  to  empty  the  well  of  oil  and  water 
by  pumping,  blowing,  or  siphoning  before  attaching  the  gauge,  for 
any  liquid  in  the  hole  will  lower  the  closed  pressure  reading. 

The  well  should  be  closed  long  enough  to  allow  the  pressure  to 
build  up  to  its  maximum.  The  length  of  time  necessary  for  this 
purpose  varies  a  great  deal  from  field  to  field  and  well  to  well.  The 
well  should  remain  closed  until  the  pressure  will  not  build  up  more 
than  1  per  cent  in  10  minutes.  Ordinarily,  24  hours  will  be  suffi- 
cient for  this  purpose,  but  for  some  wells  several  days  or  even  a 
longer  period  will  be  required,  owing  to  the  slowness  of  equalization 
of  pressure  in  the  sand. 

APPORTIONMENT  OF  DEPLETION  AMONG  VARIOUS  SANDS. 

Where  more  than  one  sand  under  a  property  is  yielding  gas,  the 
problem  arises  as  to  how  to  weight  or  evaluate  the  decline  in 
pressure  in  the  different  sands.  Suppose  there  is  a  very  good  gas 
sand  in  which  the  pressure  declines  from  600  to  300  pounds  during 
the  year,  and  a  very  poor  sand  in  which  the  pressure  declines  from 
800  to  750.  The  depletion  sustained  is  not  indicated  by  the 
average  decline  in  pressure  but  is  more  nearly  proportionate  to  the 
decline  in  the  good  sand.  If  accurate  figures  on  capacities  of  wells 
are  obtainable,  it  will  be  possible  to  make  a  fairly  accurate  weight- 
ing of  the  pressure  declines,  or  if  facts  indirectly  indicating  ca- 


MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY  35 

pacity  of  individual  wells  are  obtainable  some  light  may  be  thrown 
on  the  question.  But,  as  a  general  rule,  it  is  necessary  to  average 
the  decline  of  wells  drawing  from  different  sands  as  though  they 
were  drawing  from  the  same  sand. 

SEASON  FOR  TESTING  WELLS  FOR  CLOSED  PRESSURE. 

For  many  fields  summer  or  early  fall  readings  furnish  the  best 
indication  of  decline  in  closed  pressure.  It  is  therefore  recom- 
mended that  such  readings  be  taken  regularly  and  consistently. 
Summer  or  fall  readings  are  of  especial  value  because  these  seasons 
for  mofet  fields  are  at  the  end  of  a  period  during  which  the  wells 
have  not  been  sub'ect  to  heavy  draft,  and  hence  are  in  best  con- 
dition to  accurately  reflect  the  pressure  of  the  gas  in  the  under- 
ground pool  or  reservoir.  If  pressures  of  all  wells  or  representative 
wells  are  observed  regularly  and  carefully  in  summer  or  early  fall, 
these  readings  may  in  many  cases  be  applied  direct  to  the  end  of  the 
taxable  year,  though  in  some  cases  it  may  be  possible  and  desirable 
to  estimate  the  pressures  at  the  end  of  the  taxable  year  from  pres- 
sures observed  at  other  times.  Obviously,  it  will  not  be  possible 
to  test  the  pressures  of  all  wells  at  the  exact  end  of  the  taxable  year. 

Simple  examples. — If  in  one  part  of  a  tract  a  gas  well  is  brought 
in  at  a  pressure  of  1,000  pounds  and  during  the  remainder  of  the 
taxable  year  the  pressure  declines  to  700  pounds,  the  rough  infer- 
ence may  be  drawn  that  three-tenths  of  the  gas  has  been  taken 
from  the  tract  and,  subject  to  corrections  in  certain  cases,  three- 
tenths  of  the  capital  returnable  through  depletion  may  be  charged 
off. 

Suppose  that  sometime  in  the  next  taxable  year  a  gas  w^ell  is 
completed  on  another  part  of  the  tract  and  that  its  initial  pressure 
is  800  pounds.  If  by  the  end  of  the  year  the  pressure  of  this  well 
has  declined  to  700  pounds  while  the  pressure  of  the  first  well  has 
dropped  to  500  pounds,  the  fraction  of  the  capital  account  return- 
able through  depiction  the  second  year,  is  proportional  to  the 
average  decline  in  pressure,  assuming  that  there  are  no  water 
troubles  or  other  noteworthy  complications.  The  average  of  700 
and  800  is  750  and  the  average  of  500  and  700  is  600.  The  differ- 
ence or  average  decline  in  pounds  or  units  of  gas  is  150,  and  this 
represents  a  decline  of  20  per  cent  from  750.  It  will  be  noted 
that  the  exact  date  of  completion  of  the  new  well  does  not  enter  the 


36  MANUAL   FOR  THE  OIL  AND   GAS   INDUSTRY 

computation  and  it  is  treated  as  though  it  were  finished  at  the 
beginning  of  the  year.  The  rate  of  decHne  within  the  year  is  of 
httle  consequence,  the  main  consideration  being  the  amount  of 
decKne  for  the  whole  year.  If  the  year's  dechne  occurred  within  a 
month,  or  even  a  week,  it  is  treated  the  same  as  though  it  were 
spread  over  the  entire  year. 

Abandoned  wells  may  be  regarded  as  fully  depleted  and  their 
pressure  counted  as  zero  in  computing  depletion.  Consider  the 
wells  just  described  and  assume  that  in  the  third  year  a  third  well 
is  brought  in  and  one  of  the  old  wells  is  abandoned.  Suppose  the 
pressure  at  the  first  well  declined  from  500  pounds  to  about  zero 
and  the  well  is  abandoned,  the  second  well  to  300  pounds  and  the 
third  to  600.  The  pressure  of  the  two  old  wells  at  the  beginning  of 
the  year  and  of  the  new  one  at  its  completion  averaged  600  pounds, 
and  the  average  of  the  three  at  the  end  of  the  year  was  300.  The 
depletion  indicated  is  50  per  cent  of  the  remaining  capital  account. 

It  is  suggested  that  the  capital  sum  at  the  beginning  of  each 
year  be  treated  as  100  per  cent  for  the  average  pressure  at  the 
beginning  of  the  year,  and  the  average  decline  during  the  year  will 
then  furnish  a  readily  usuable  basis  for  computing  the  depletion 
allowance. 

The  amount  of  gas  in  the  ground  is,  as  a  rule,  to  be  regarded  as 
limited  to  the  proven  territory  so  that  as  new  wells  are  drilled  and 
the  territory  is  enlarged,  or  new  gas-bearing  sands  are  discovered, 
the  denominator  of  the  fraction,  indicating  depletion,  varies  from 
year  to  year. 

FORMULA. 

The  following  discussion  is  offered  for  the  use  of  those  who 
prefer  to  use  a  formula  in  computing  the  depletion  allowance. 
Perhaps  the  simplest  formula  may  be  written: 

-Xz  =  depletion  allowance. 

'  y 

In  this  formula  x  stands  for  the  capital  sum  to  the  end  of  the 
year;  y  is  the  total  future  pressure  decline  or  the  difference  between 
the  sum  of  the  pressures  at  the  beginning  of  the  tax  year  and  the 
sum  of  the  pressures  at  the  time  of  expected  abandonnient;  z  is 


MANUAL  FOR  THE  OIL  AND   GAS  INDUSTRY  37 

the  pressure  decline  during  the  year  as  obtained  by  adding  to  the 
sum  of  the  pressures  at  the  beginning  of  the  year  the  sum  of  the 
pressures  of  any  new  wells  completed  during  the  A^ear  and  sub- 
tracting the  sum  of  the  pressures  at  the  end  of  the  year.  The 
formula  may  also  be  written  as  follows: 

Sum  of  pressures 
at  beginning  of 
Capital  sum  to  end  of  tax  year  tax  year  +  _  Depletion 
Sum  of  the  pressures  at  begin-  sum  of  pres-  allowance, 
ning  of  year  — sum  of  pressures  sures  of  new 
at  time  of  expected  abandon-  wells  —  sum 
ment.  of  pressures  at 

end  of  tax  year. 

GAS  WELL  PRESSURE  RECORDS  TO  BE  KEPT. 

Regulations  45,  article  212. — Beginning  with  1919,  closed- 
pressure  readings  of  representative  wells,  if  not  of  all  wells,  must  be 
carefully  made  and  kept.  In  order  to  standardize  pressure  read- 
ings, the  well  should  remain  closed  until  the  pressure  does  not 
build  up  more  than  1  per  cent  of  the  total  pressure  in  10  minutes. 
Ordinarily  24  hours  will  suffice  for  this  purpose  but  some  wells 
will  need  to  remain  closed  for  a  longer  period.  Where  the  pressure 
builds  up  very  slowly  the  1  per  cent  in  10  minutes  will  be  found  too 
liberal.  If  there  is  any  water  in  the  well  it  should  be  blown,  si- 
phoned, or  pumped  off  before  the  well  is  closed. 

A  closed-pressure  reading  of  a  gas  well  which  has  been  produc- 
ing, or  is  near  gas  wells  that  have  been  producing,  is  lower  than  the 
actual  average  pressure  of  the  gas  in  the  reservoir  by  an  amount 
depending  on  the  well's  location  with  reference  to  other  producing 
wells  and  the  length  o-  time  it  has  been  closed  in. 

It  is  necessary  to  record  the  length  of  time  the  well  has  been 
closed  and  to  show  how  the  pressure  built  up  during  this  period. 
Successive  readings  will  indicate  the  point  at  which  the  pressure 
becomes  approximately  stationaiy ;  that  is,  the  point  at  which  the 
closed  pressure  approaches  as  nearly  as  possible  the  maximum 
pressure  which  would  be  shown  if  all  wells  in  the  pool  were  closed 
for  several  months.  The  length  of  time  required  varies  with  the 
character  of  the  sand,  position  of  the  packer,  the  location  of  the 


:^ 


38  MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY 

well  with  reference  to  other  wells,  the  limits  of  the  pool,  and  other 
factors.  The  depth  of  the  well,  diameter  of  tubing,  and  line 
pressure  when  the  well  was  shut  off  should  be  noted. 

Since  readings  at  the  exact  end  of  the  taxable  year  will  ordi- 
arily  not  be  available,  the  pressure  of  that  date  may  be  obtained 
by  interpolation  or  extrapolation.  In  certain  cases  readings  taken 
regularly  in  September  or  some  other  month  may  be  applicable  to 
the  end  of  the  taxable  year.  As  a  general  rule  September  closed- 
pressure  readings  furnish  the  best  indication  of  depletion,  and  it  is 
recommended  that  such  readings  be  made  with  regularity  and  care. 
Where  interpolated  or  extrapolated  readings  are  used,  the  data 
from  which  they  are  obtained  should  be  given.  Gauges  should  be 
of  appropriate  capacity  and  should  be  frequently  tested.  Record 
should  be  kept  of  the  number  of  gauges,  date  each  was  tested, 
names  of  men  testing,  and  other  significant  details. 

COMPUTATION  OF  COMPLETION  ALLOWANCES  WHERE  QUANTITY 
OF  OIL  OR  GAS  IS  UNCERTAIN. 

Regulations  45,  article  213. — Computation  of  depletion  allow- 
ance where  quantity  of  oil  or  gas  uncertain. — If  by  reason  of  the 
youth  of  the  field,  restricted  production  or  for  any  other  cause,  it 
is  not  possible  to  determine  with  any  degree  of  certainty  the 
quantity  of  oil  or  gas  in  a  property,  it  will  be  necessary  to  make  a 
tentative  estimate  which  will  apply  until  production  figures  are 
available  from  which  an  accurate  estimate  may  be  made. 

COMPUTATION  OF  DEPLETION  ALLOWANCE  FOR  COMBINED 
HOLDINGS  OF  OIL  PROPERTIES. 

Regulations  45,  article  214  (1). — The  recoverable  oil  belonging 
to  the  taxpayer  shall  be  estimated  separately  on  the  smallest 
unit  on  which  data  are  available,  such  as  individual  wells  or  tracts, 
and  these,  added  together  into  a  grand  total,  to  be  apphed  to  the 
total  capital  assets  returnable  through  depletion. 

The  capital  sum  shall  include  the  cost  or  value,  as  the  case  may 
be,  of  all  oil  rights,  freeholds,  or  leases,  plus  all  incidental  costs  of 
development  not  charged  as  expense. 

The  unit  value  of  the  total  recoverable  oil  is  the  quotient 
obtained  by  dividing  the  total  capital  sum  recoverable  through 


MANUAL   FOR  THE   OIL  AND   GAS  INDUSTRY  39 

depletion  by  the  total  estimated  recoverable  oil  at  the  beginning 
of  the  taxable  year. 

This  unit  multiplied  by  the  total  number  of  units  of  oil  produced 
by  the  taxpayer  during  the  taxable  year  from  all  of  the  oil  prop- 
erties will  determine  the  amount  which  may  be  allowably  deducted 
from  the  gross  income  of  that  year. 

In  the  case  of  sale  of  particular  tracts,  full  account  must  be 
taken  of  the  depletion  of  such  tracts  in  computing  profit  or  loss 
thereon. 

COMPUTATION  OF  DEPLETION  ALLOWANCE  FOR  COMBINED 
HOLDINGS  OF  GAS  PROPERTIES. 

Regulation  45,  article  214  (2) . — In  the  case  of  gas  properties  of  a 
taxpayer  the  depletion  allowance  for  each  pool  may  be  computed 
by  using  the  combined  capital  sum  returnable  through  depletion 
of  all  tracts  of  gas  land  owned  by  the  taxpayer  in  the  pool  and  the 
average  decline  in  rock  pressure  of  all  the  taxpayer's  wells  in  each 
pool  in  the  formula  given  in  article  211.  The  total  allowance  for 
depletion  of  the  gas  properties  of  the  taxpayer  will  be  the  sum  of 
the  amounts  computed  for  each  pool. 

The  depletion  of  gas  supplies  belonging  to  a  taxpayer  may  be 
more  accurately  computed  by  making  estimates  for  each  tract, 
though  it  is  quite  possible  tha  the  expense  of  making  separate 
estimates  for  individual  tracts  may  be  greater  than  the  benefits 
arising  from  such  a  procedure. 

DEPLETION  AND  DEPRECIATION  ACCOUNTS  OF  BOOKS. 

Regulation  45,  article  216. — Every  taxpayer  claiming  and  mak- 
ing a  deduction  for  depiction  and  depreciation  of  mineral  property 
shall  keep  accurate  ledger  accounts  in  which  shall  be  charged  the 
fair  market  value  as  of  March  1,  1913,  or  within  30  days  after  the 
date  of  discovery,  or  the  cost,  as  the  case  may  be  (a)  of  the  prop- 
erty, and  (6)  of  the  plant  and  equipment,  together  with  (c)  such 
amounts  expendcMl  for  development  of  the  property  or  additions 
to  plant  and  equipment  since  that  date  as  have  not  been  deducted 
as  expense  in  his  returns. 

These  accounts  shall  bo  ereclited  with  the  amount  of  the  depre- 
ciation and  dei~)l('tion  deductions  claimed  and  allowed  each  year, 
or  the  aniounts  of  the  depreciation  and  depiction  shall  be  credited 


40  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

to  depletion  and  depreciation  reserve  accounts,  to  the  end  that 
when  the  sum  of  the  credits  for  depletion  and  depreciation  equals 
the  value  or  cost  of  the  property  plus  the  amount  added  thereto 
for  development  or  additional  plant  and  equipment,  less  salvage 
value  of  the  physical  property,  no  further  deduction  for  depletion 
and  depreciation  with  respect  to  the  property  will  be  allowed. 

Because  of  the  fact  that  depreciation  and  depletion  deductions 
are  applied  against  different  capital  sums,  which  are  usually  return- 
able at  different  rates,  it  is  essential  that  these  accounts  be  kept 
separately;  that  is,  the  cost  or  value  of  physical  property  subject 
to  depreciation  with  deductions  for  depreciation  enter  into  one 
account,  while  the  cost  or  value  of  the  property  (exclusive  of  physi- 
cal property),  together  with  additions  for  such  development  costs 
as  have  not  been  charged  to  current  operating  expenses  or  deducted 
as  depletion,  enter  into  a  separate  account. 

If  dividends  are  paid  out  of  a  depletion  or  depreciation  reserve, 
the  stockholders  must  be  expressly  notified  that  the  dividend  is  a 
return  of  capital  and  not  an  ordinary  dividend  out  of  profits. 

DISTRIBUTION  FROM  DEPLETION  OR  DEPRECIATION  RESERVE. 

A  reserve  set  up  out  of  gross  income  by  a  corporation  and  main- 
tained for  the  purpose  of  making  good  any  loss  of  capital  assets  on 
account  of  depletion  or  depreciation  is  not  a  part  of  its  surplus  out 
of  which  ordinary  dividends  may  be  paid. 

A  distribution  made  from  such  a  reserve  will  be  considered  a 
liquidatmg  dividend  and  will  constitute  taxable  income  to  a  stock- 
holder only  to  the  extent  that  the  amount  so  received  is  in  excess 
of  the  cost  or  fair  market  value  as  of  March  1,  1913,  of  his  shares  of 
stock.  No  distribution,  however,  will  be  deemed  to  have  been 
made  from  such  a  reserve,  except  to  the  extent  that  the  amount 
paid  exceeds  the  surplus  and  undivided  profits  of  the  corporation. 

In  general,  any  distribution  made  by  a  corporation  other  than 
out  of  earnings  or  profits  accumulated  since  February  28,  1913,  is 
to  be  regarded  as  a  return  to  the  stockholder  of  part  of  the  capital 
represented  in  his  shares  of  stock,  and  upon  a  subsequent  sale  of 
such  stock  his  profit  will  be  the  excess  of  the  selling  price  over  the 
cost  of  the  stock  or  its  fair  market  value  as  of  March  1,  1913, 
after  applying  on  such  cost  or  value  the  amount  of  any  such  capital 
distribution. 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY  41 


STATEMENT  TO  BE  ATTACHED  TO  RETURN  WHERE  DEPLETION 
OF  OIL  OR  GAS  IS  CLAIMED. 

Regtlations  45,  article  218. — To  each  return  made  by  a  person 
owning  or  operating  oil  or  gas  properties  there  should  be  attached  a 
statement  showing  for  each  property  information  called  for  in 
Schedules  I,  II,  and  IV. 

(a)  (1)  The  fair  market  value  of  the  property  (exclusive  of 
machinery,  equipment,  etc.,  and  the  value  of  the  surface  rights) 
as  of  March  1,  1913,  if  acquired  prior  to  that  date;  or  (2)  the  fair 
market  value  of  the  property  within  30  days  after  the  date  of 
discovery;  or  (3)  the  actual  cost  of  the  property,  if  acquired  sub- 
sequent to  February  28,  1913,  and  not  covered  by  the  foregoing 
clause : 

(b)  How  the  fair  market  value  was  ascertained,  if  the  property 
came  under  (a)  (1)  or  (a)  (2)  above  (see  sections  relating  to  fair 
market  value,  p.  23) ; 

(c)  The  estimated  quantity  of  oil  or  gas  in  the  property  at  the 
time  that  the  value  or  cost  was  determined; 

(d)  The  name  and  address  of  the  person  making  the  estimate 
and  the  manner  in  which  this  estimate  was  made,  including  a 
summary  of  the  calculations; 

(e)  The  amount  of  capital  applicable  to  each  unit  (this  being 
found  by  dividing  the  value  or  cost,  as  the  case  may  be,  by  the 
estimated  number  of  units  of  oil  or  gas,  pounds  per  square  inch  in 
the  case  of  gas)  in  the  property  at  the  beginning  of  the  taxable 
year; 

(/)  The  quantity  of  oil  or  gas  produced  during  the  year  for 
which  the  return  is  made  (in  the  case  of  new  properties  it  is  desir- 
able fhat  this  information  be  furnished  by  months) ; 

(g)  The  number  of  acres  of  producing  and  proven  oil  or  gas 
land: 

(h)  The  number  of  wells  producing  at  the  beginning  and  end 
of  the  taxable  year; 

(i)  The  date  of  completion  of  wells  finished  during  the  taxable 
year; 

(j)  The  date  of  abandonment  of  all  wells  abandoned  during 
the  taxable  year ; 

(k)  A  legal  description  of  the  property,  with  a  property  map 


42  MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY 

showiHg  the  location  of  the  property  and  of  the  producing  and 
abandoned  wells,  dry  holes,  and  proven  oil  and  gas  land; 

(Z)  The  average  gravity  of  the  oil  produced  on  the  tract; 

(m)  The  nun.ber  of  pay  sands  and  average  thickness  of  each 
pay  sand  or  zone  on  the  property ; 

(n)  The  average  depth  to  the  top  of  each  of  the  different  pay 
sands; 

(o)  Any  data  regarding  change  in  operating  conditions,  such 
as  flooding,  use  of  compressed  air,  vacuum,  shooting,  etc.,  which 
have  a  direct  effect  on  the  production  of  the  property; 

(p)  The  monthly  or  annual  production  of  individual  wells  and 
the  initial  daily  production  of  new  wells  (this  is  highly  desirable 
information  and  should  be  furnished  wherever  possible) ; 

(q)  (For  the  first  year  in  which  the  above  information  is  filed 
for  a  property  which  was  producing  prior  to  the  taxable  year  cov- 
ered by  the  above  statement  the  following  information  must  be 
furnished.)  Annual  production  of  the  tract  or  of  the  individual 
wells,  if  the  latter  information  is  available,  from  the  beginning  of 
its  productivity  to  the  beginning  of  the  taxable  year  for  which  the 
return  was  filed;  the  average  number  of  wells  producing  each  year; 
and  the  initial  daily  production  of  each  well ;  and 

(r)  Any  other  data  which  will  be  helpful  in  determining  the 
reasonableness  of  the  depletion  deduction. 

Maps. 

Maps  that  accompany  records  and  delineate  property  boun- 
daries must  be  sufficiently  extended  to  show  the  position  of  prop- 
erty in  relation  to  section,  township,  and  range  lines,  or  in  areas 
of  metes  and  bounds  survey,  the  relation  to  two  or  more  estab- 
lished lines,  of  either  township  or  district. 

On  some  part  of  the  map  should  be  recorded  the  name  of  the 
State,  county,  township,  or  district,  name  of  the  company  or 
individual  representing  property,  scale  of  map,  and  date  of  survey, 
and  points  of  the  compass. 

It  will  be  to  the  advantage  of  every  taxpayer  to  assist  the  de- 
partment in  compiling  complete  statistics  of  all  development  that 
has  taken  place,  and  maps  submitted  should  show  location  of  all 
wells  that  have  ever  been  drilled  on  a  given  property.  The  char- 
acter of  each  well  should  be  indicated  by  appropriate  symbols. 


MANUAL   FOR  THE  OIL  AND   GAS   INDUSTRY  43 

Where  wells  have  been  drilled  by  another  company  or  indi- 
vidual it  is  advisable  to  distinguish  such  wells  by  some  ifj'mbol  or 
abbreviation,  explaining  the  symbol  in  a  marginal  note. 

When  a  taxpayer  has  filed  adequate  maps  with  the  Commis- 
sioner he  may  be  relieved  of  filing  further  maps  of  the  same 
properties,  provided  all  additional  information  necessary  for  keep- 
ing the  maps  up  to  date  is  filed  each  year.  This  includes  records 
of  dry  holes  as  well  as  producing  wells,  together  with  logs,  depth, 
and  thickness  of  sands,  location  of  new  wells,  etc. 

By  "  production  "  is  meant  the  net  production  of  oil  or  gas 
belonging  to  the  taxpayer. 

In  those  leases  where  no  account  is  kept  of  the  oil  or  gas  used 
for  fuel,  the  net  production  will  necessarily  be  that  remaining  after 
the  fuel  used  in  the  property  has  been  taken  out.  In  cases  of  this 
kind  an  estimate  of  the  fuel  used  frozn  each  tract  should  be  given 
for  each  year. 

REVALUATION  OF  OIL  OR  GAS  PROPERTIES  DISCO^/ERED  SINCE 

MARCH  1,  1913. 

Section  214  (a)  and  234  (a)  of  the  Revenue  Act  of  1918,  state — 

that  in  the  case  of  mines,  oil  and  gas  wells,  discovered  by  the  taxpayer  on  or 
after  March  1,  1913,  and  not  acciuired  as  a  result  of  purchase  of  a  proven  tract 
or  lease,  where  the  fair  market  value  of  the  property  is  materially  dispropor- 
tionate to  the  cost,  the  depletion  allowance  shall  be  based  on  the  fair  market 
value  of  the  property  at  the  date  of  the  discovery  or  within  30  days  there- 
after; such  reasonable  allowance  ...  to  be  made  under  rules  and  regulations 
to  be  prescribed  by  the  Commissioner,  with  the  approval  of  the  Secretary. 
In  the  case  of  the  leases  the  deductions  allowed  by  this  paragraph  shall  be 
equitably  apportioned  between  the  lessor  and  lessee. 

Extract  from  Regulations  45: 

Art.  220.  Oil  and  gas  wells. — Section  214  (a)  (10)  and  section 
234  (a)  (9)  provide  that  taxpayers  who  discover  oil  and  gas  wells 
on  or  after  March  1,  1913,  may,  under  the  circumstances  therein 
prescribed,  determine  the  fai  market  value  of  such  property  at 
the  date  of  discove  y  or  within  30  days  thereafter  for  the  purpose 
of  asceitaining  allowable  deductions  for  depletion.  Before  such 
valuation  may  be  made  the  statute  requires  that  two  conditions 
precedent  be  satisfied,  (1)  that  the  fair  market  value  of  such 
property  (oil  and  gas  wells)  on  the  date  of  discovery  or  within  30 


44  MANUAL   FOR  THE  OIL   AND   GAS   INDUSTRY 

days  thereafter  became  materially  disproportionate  to  the  cost, 
by  virtue  of  the  discovery,  and  (2)  that  such  oil  and  gas  wells 
were  not  acquired  as  the  result  of  purchase  of  a  proven  tract  or 
lease. 

Art.  220  (a).  Discovery — Proven  tract  or  lease — Property 
disproportionate  value. — (1)  For  the  purpose  of  these  sections  of 
the  revenue  act  of  1918,  an  oil  or  gas  well  may  be  said  to  be  dis- 
covered when  there  is  either  a  natural  exposure  of  oil  or  gas,  or  a 
drilling  that  discloses  the  actual  and  physical  presence  of  oil  or 
gas  in  quantities  sufficient  to  justify  commercial  exploitation. 
Quantities  sufficient  to  justify  commercial  exploitation  are 
deemed  to  exist  when  the  quantity  and  quality  of  the  oil  or  gas  so 
recovered  from  the  well  are  such  as  to  afford  a  reasonable  expec- 
tation of  at  least  returning  the  capital  invested  in  such  well 
through  the  sale  of  the  oil  or  gas,  or  both,  to  be  derived  therefrom. 

(2)  A  proven  tract  or  lease  may  be  a  part  or  the  whole  of  a 
proven  area.  A  proven  area  for  the  purposes  of  this  statute  shall 
be  presumed  to  be  that  portion  of  the  productive  sand  or  zone  or 
reservoir  included  in  a  square  surface  area  of  160  acres  having  as 
its  center  the  mouth  of  a  well  producing  oil  or  gas  in  commercial 
quantities.  In  other  words,  a  producing  well  shall  be  presumed 
to  prove  that  portion  of  a  given  sand,  zone,  or  reservoir  which  is 
included  in  an  area  of  160  acres  of  land,  regardless  of  private  boun- 
daries. The  center  of  such  square  ai^a  shall  be  the  mouth  of  the 
well,  and  its  sides  shall  be  parallel  to  the  section  lines  established 
by  the  United  States  system  of  public  land  surveys  in  the  district 
in  which  it  is  located.  Where  a  district  is  not  covered  by  the 
United  States  land  surveys,  the  sides  of  said  area  shall  run  north 
and  south,  east  and  west. 

So  much  of  a  taxpayer's  tract  or  lease  which  lies  within  an 
area  proven  either  by  himself  or  by  another  is  "  proven  tract  or 
lease  "  as  contemplated  by  the  statute,  and  the  discovery  of  a  well 
thereon  will  not  entitle  such  taxpayer  to  revalue  such  well  for  the 
purpose  of  depletion  allowances,  unless  the  tract  or  lease  had  been 
acquired  before  it  became  proven.  And  even  though  a  well  is 
brought  in  on  a  tract  or  lease  not  included  in  a  proven  area  as 
heretofore  defined,  nevertheless  it  may  not  entitle  the  owner  of 
the  tract  or  lease  in  which  such  well  is  located  to  revaluation  for 
depletion  purposes,  if  such  tract  or  lease  lies  within  a  compact  area 
which  is  immediately  surrounded  by  proven  land,  and  the  geologic 


MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY  45 

structural  conditions  on  or  under  the  land  so  inclosed  may  reason- 
ably warrant  the  belief  that  the  oil  or  gas  of  the  proven  areas 
extends  thereunder.  Under  such  circumstances  the  entire  area 
is  to  be  regarded  as  proven  land. 

(3)  The  "  property  "  wliich  may  be  valued  after  discovery  is 
the  "  well."  For  the  purposes  of  these  sections  the  "  well  "  is 
the  drill  hole,  the  surface  necessary  for  the  drilling  and  operation 
of  the  well,  the  oil  or  gas  content  of  the  particular  sand,  zone,  or 
reservoir  (limestone,  breccia,  crevice,  etc.)  in  which  the  discovery 
was  made  by  the  drilling,  and  from  which  the  production  is  drawn, 
to  the  limit  of  the  taxpayer's  private  bounding  lines,  but  not  beyond 
the  limits  of  the  proven  area  as  heretofore  provided. 

(4)  A  taxpayer  to  be  entitled  to  revalue  his  property  after 
March  1,  1913,  for  the  purpose  of  depletion  allowances  must  make 
a  discovery  after  said  date  and  such  discovery  must  result  in  the 
fair  market  value  of  the  property  becoming  disproportionate  to 
the  cost.  The  fair  market  value  of  the  property  will  be  deemed 
to  have  become  disproportionate  to  the  cost  when  the  output  of 
such  well  of  oil  or  gas  affords  a  reasonable  expectation  of  returning 
to  the  taxpayer  an  amount  materially  in  excess  of  the  cost  of  the 
land  or  lease  if  acquired  since  March  1,  1913,  or  its  fair  market 
value  on  March  1,  1913,  if  acquired  prior  thereto,  plus  the  cost  of 
exploration  and  development  work  to  the  time  the  well  was 
brought  in. 

Art.  221.  Proof  of  discovery  of  oil  and  gas  wells. — In  order 
to  meet  the  requirements  of  the  preceding  article  to  the  satisfaction 
of  the  commissioner,  the  taxpayer  will  be  required,  among  other 
things,  to  submit  the  following  with  his  return:  (a)  A  map  of  con- 
venient scale,  showing  the  location  of  the  tract  and  discovery  well 
in  question  and  of  the  nearest  producing  well,  and  the  develop- 
ment for  a  radius  of  at  least  3  miles  from  the  tract  in  question, 
both  on  the  date  of  discovery  and  on  the  date  when  the  fair  market 
value  was  set;  (b)  a  certified  copy  of  the  log  of  the  discovery  well 
showing  the  location,  the  date  drilling  began,  the  date  of  com- 
pletion and  beginning  of  production,  the  formations  penetrated, 
the  oil,  gas,  and  water  sands  penetrated,  the  casing  record,  includ- 
ing the  record  of  perforations,  and  any  other  information  tending 
to  show  the  concUtion  of  the  well  and  the  location  of  the  sand  or 
zone  from  which  the  oil  or  gas  is  prochiced  on  the  date  the  discovery 
was  claimed;   (c)  a  sworn  record  of  proihiction,  clearly  jiroving  ihc 


46  MANUAL  FOR  THE   OIL  AND   GAS  INDUSTRY 

commercial  productivity  of  the  discovery  well;  (d)  a  sworn  copy 
of  the  records,  showing  the  cost  of  the  property;  and  (e)  a  full 
explanation  of  the  method  of  determining  the  value  on  the  date  of 
discovery  or  within  30  days  thereafter,  supported  by  satisfactory 
evidence  of  the  fairness  of  tliis  value. 

CHARGES  TO  CAPITAL  AND  TO  EXPENSE  IN  THE  CASE  OF  OIL 
AIID  GAS  WELLS. 

Regulations  45,  article  223. — Such  incidental  expenses  as  are 
paid  for  wages,  fuel,  repairs,  hauling,  etc.,  in  connection  with  the 
exploration  of  property,  drilling  of  wells,  building  pipe  lines,  and 
development  of  the  property,  may,  at  the  option  of  the  taxpayer, 
be  deducted  as  an  operating  expense  or  charged  to  the  capital 
sum  returnable  through  depletion.  If  the  taxpayer  elects  to 
charge  such  well  and  development  costs  to  operating  expenses,  the 
amount  so  charged  can  not  be  included  in  invested  capital  on  which 
excess  profits  tax  is  computed,  and  the  policy,  once  adopted,  must 
be  followed  in  subsequent  years. 

If  in  exercising  this  option  the  taxpayer  charges  these  incidental 
expenses  to  capital  sum,  in  so  far  as  such  expense  is  represented  by 
physical  property,  it  may  be  taken  into  account  in  determining  a 
reasonable  allowance  for  depreciation.  The  cost  of  drilling  non- 
productive wells  may,  at  the  option  of  the  operator,  be  deducted 
from  gross  income  as  an  operating  expense  or  charged  to  capital 
sum  returnable  through  depletion  and  depreciation  as  in  the  case 
of  productive  wells.  The  taxpayer  should  adopt  a  consistent 
poHcy  as  to  capitalizing  or  charging  off  cost  of  drilhng  non- 
productive wells. 

Casing-head  gas  contracts  have  been  construed  to  be  tangible 
assets  and  their  cost  may  be  added  to  the  capital  sum  returnable 
through  depletion,  following  the  rate  set  by  the  oil  or  gas  wells 
from  which  the  gas  is  derived,  or,  if  the  life  of  the  contract  is  shorter 
than  the  reasonable  expectation  of  the  life  of  the  wells  furnishing 
the  gas,  the  capital  invested  in  the  contract  may  be  written  off 
through  yearly  allowances  equitably  distributed  over  the  life  of  the 
contract. 

All  oil  produced  during  the  taxable  year,  whether  sold  or 
unsold,  must  be  considered  in  the  computation  of  the  depletion 
allowance  for  the  taxable  year.     However,  oil  on  hand  at  the 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY  47 

beginning  and  end  of  the  year  must,  in  computing  net  income,  be 
inventoried  at  cost  or  estimated  cost  (including  depletion  or  cost 
in  the  ground,  plus  lifting  charges). 

Where  deductions  for  depreciation  or  depletion  have  either  on 
the  books  of  the  taxpayer  or  in  his  returns  of  net  income  been 
included  in  the  past  in  expense  or  other  accounts,  rather  than 
specifically  as  depreciation  or  depletion,  or  where  capital  expendi- 
tures have  been  charged  to  expense  in  lieu  of  depreciation  or 
depletion,  a  statement  indicating  the  extent  to  which  this  prac- 
tice has  been  carried  should  accompany  the  return. 

DEPLETION  FOR  PAST  YEARS  NOT  ALLOWED  BY  DEPARTMENT. 

Where  under  the  act  of  October  3,  1913,  or  of  September  8, 
1916,  a  taxpayer  has  not  been  allowed  to  make  a  deduction  for  the 
full  amount  of  his  depletion,  the  amount  of  such  deficiency  can 
not  be  carried  forward  and  deducted  in  any  later  year.  Depletion 
attaches  to  each  unit  of  mineral  or  other  property  removed,  and  a 
taxpayer  should  make  proper  provision  therefor  in  computing 
his  net  income.  Under  the  Revenue  Act  of  1918  the  amount 
recoverable  through  depletion  will  be  the  cost,  or  the  value  as  of 
March  1,  1913,  or  within  30  days  of  the  date  of  discovery,  as  the 
case  may  be,  less  proper  allowance  for  the  mineral  or  other  prop- 
erty removed  prior  to  January  1,  1918. 

APPENDIX  TO  PART  I. 
SCHEDULES. 

/.  Schedule  for  Ascertaining  Cost  of  Property  as  of  any  Specified 

Date. 

1.  Name  of  property. 

2.  Location  of  property. 

3.  Are  you  sole  owner  of  property? 

4.  If  not  sole  owner,  your  ownership  interest  therein. 

5.  Is  property  a  leasehold? 

6.  (a)  If  so,  name  and  address  of  lessor  and  lessee. 

(b)  Date  lease  effective. 

(c)  Date  of  expiration. 

(d)  Royalty  rate. 

(e)  Bonus,  either  cash  or  property. 


48  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

7.  Date  property  was  acquired. 

8.  (a)  Manner  of  acquisition:   (Purchase,  trade,  gift,  etc) 
(6)  Amount  paid  in  cash. 

(c)  Amount  paid  in  stock. 

(1)  Par  value  of  stock. 

(2)  Actual  cash  value  of  stock. 

(3)  How  was  this  cash  value  established? 

(d)  Amount  paid  in  bonds. 

(1)  Par  value  of  bonds. 

(2)  Actual  cash  value  of  bonds. 

(3)  How  was  this  cash  value  established? 

(e)  Amount  paid  in  other  considerations. 

(1)  What  were  the  considerations? 

(2)  State  actual  cash  value  of  these  considerations. 

(3)  Manner  of  determining  this  cash  value. 

(4)  Name  and  address  of  party  establishing  value. 

(5)  Append  a  copy  of  the  report  of  the  part}^  estab- 
lishing cash  value  of  a  resume  of  his  report. 

(/)  Cash  value  of  total  consideration  paid  for  property  as 
estabhshed  by  you. 

Map. 

9.  Map  showing  as  of  date  of  acquisition,  location  of  the 
property,  property  boundaries,  and  location  of  all  wells  and  other 
developments  in  this  vicinity. 

This  map  must  be  on  a  convenient  scale,  preferably  of  not  less 
than  1/3180  or  2  inches  to  the  mile  for  developed  areas,  and  should 
show  the  following  information  for  each  tract  as  of  date  of  acqui- 
sition: 

(a)  Wells  producing. 

(6)  Wells  temporarily  suspended. 

(c)  Wells  formerly  productive  but  now  abandoned. 

(d)  Wells  completed  to  oil  or  gas  sand  or  zone  but  non-pro- 

ductive. 

(e)  Wells  abandoned  before  completion. 
(/)  Wells  drilling. 

(g)  Area  considered  (1)  producing,  (2)  proven,  (3)  highly 
probable,  and  (4)  possible  oil  and  /or  gas  lands,  and  (5)  land  worth- 
less for  oil  and  /or  gas  production.     (Proven  or  proved  oil  or  gas 


MANUAL  FOR  THE  OIL  AND  GAS   INDUSTRY  49 

land  is  that  which  has  been  shown  by  finished  wells,  supplemented 
by  geologic  data,  to  be  such  that  other  wells  drilled  thereon  are 
practically  certain  to  be  commercial  producers.) 

In  the  case  of  a  company  owning  more  than  one  tract  in  a  single 
pool  or  field,  a  field  map  folded  to  letter-size  dimensions,  say,  8  by 
10  inches,  if  not  too  cumbersome,  may  be  sent,  and  each  tract 
designated  by  a  letter  or  some  other  convenient  symbol. 

Lajid  Data. 

10.  Area  in  acres  as  of  date  of  acquisition  of — 
(a)  Fully  developed  oil  or  gas  territory. 
(6)   Proven  oil  or  gas  territory. 

(c)  Highly  probable  oil  or  gas  territory. 

(d)  Possible  oil  or  gas  territoiy. 

(e)  Territory  worthless  for  oil  or  gas  production. 
(/)  Total  acreage. 

11.  Name  and  address  of  the  party  making  land  classification 
as  covered  in  questions  9  and  10. 

Well  Data. 

12.  Furnish  the  following  information  as  of  date  of  acquisition: 

(a)  Number  of  wells  producing. 

(b)  Number  of  wells  abandoned  or  temporarily  suspended. 

(c)  Nuniber  of  wells  drilling. 

(d)  Number  of  new  locations  yet  remaining  undrilled  on 

proven  territory. 

13.  (a)  Number  of  producing  oil  and  /or  gas  sands  proven  on 

property. 
(6)  Designation  of  the  different  sands,  with  the  average 
thickness  of  each  and  average  depth  from  surface 
to  the  top  of  each  sand. 

(c)  Any  other  information  regarding  conditions  in  wells 

which  might  be  used  to  classify  the  wells  in  groups. 

(d)  List  of  wells  as  of  date  of  acquisition,  showing  the  fol- 

lowing information  regarding  each: 

(1)  Number  or  letter  by  which  each  is  designated. 

(2)  Date  of  beginning  drilling. 

(3)  Date  of  beginning  of  production. 


50  MANUAL   FOR   THE  OIL   AND   GAS  INDUSTRY 

(4)  Date  abandoned. 

(5)  Initial  daily  production. 

14.  Subniit  table  showing — 

(a)  Production  of  tract  by  calendar  years  from  the  begin- 

ning of  production  to  date  of  acquisition,  with 
average  number  of  wells  producing  each  yeai 
(6)  The  same  information  for  calendar  years  subsequent 
to  date  of  acquisi  ion. 

(c)  Amount  received  each  year  for  production  mentioned 

in  (a)  and  (6). 

(d)  Average  price  per  barrel  received  for  oil,  given  by 

years  since  production  began. 

(e)  Total  production  prior  to  date  of  acquisition,  in  barrels. 
(/)    Total  production  subsequent  to  date  of  acquisition, 

in  barrels. 
(g)  Total  amount  received  for  production  mentioned  in  (e) 

and  (/). 
(/i)  If  the  tract  or  wells  have  been  producing  for  less  than 

two  years,  monthly  production  figures  must  be 

furnished. 

15.  (a)  Production  of  individual  wells,  by  calendar  years  from 

beginning  of  production  to  date  of  acquisition,  if 

such  data  are  available. 
(h)  Same  information  for  period  subsequent  to  date  of 

acquisition, 
(c)   If,  through  any  cause,  it  is  impossible  to  give  yearly 

production  records  by  individual  wells,  state  the 

reasons  why  this  information  is  not  available. 

Oil  and  Gas  Reserves  in  Property. 

16.  (a)  What  was  the  estimated  total  number  of  units  of  oil 
and/or  gas  in  the  property  on  date  of  acquisition? 

(6)  How  was  this  estimate  made?    ■ 

(c)  Append  a  copy  of  the  appraisal  from  which  the  esti- 

mates were  derived  or  append  a  resume  of  the 
calculations  utilized  in  making  the  estimate. 

(d)  Give  name  and  address  of  party  making  the  estimate. 

17.  (a)  State  range  in  specific  gravity  of  oil  recovered. 

(b)  State  average  specific  gravity  oil  delivered. 


MANUAL  For  the  oil  and  gas  industry         51 

(c)   If  more  than  one  grade  delivered,  give  percentage  of 
each  for  a  year  of  acquisition. 


Casing-head  Gas. 

18.  Submit  table  Fhowing — 

(a)  Quantity  of  casing-head  gas  produced  by  months  from 
date  of  first  production  to  date  of  acquisition. 

(6)  Quantity  of  casing-head  gas  produced  by  months  for 
period  subsequent  to  date  of  acquisition. 

(c)  Average  number  of  wells  contributing  to  this  produc- 

tion each  year, 

(d)  In  case  the  gas  i>  sold,  give  the  amount  received  each 

month  f o    gas  mentioned  in  (a)  and  (6) . 

(e)  Quantity  of  gasoline  in  gallons  recovered  each  year 

from  casing-head  gas,  mentioned  in  (a)  and  (b). 

(/)  Amount  received  each  month  for  gasoline  mentioned 
in  (e). 

(g)  Average  price  per  gallon  received  for  gasoline  men- 
tioned in  (e). 

(h)  Production  of  oil  by  months  for  the  wells  from  which 
this  casing-head  gas  is  taken.  Give  this  informa- 
tion by  individual  wells  if  possible;  if  not,  then  by 
tracts  with  number  of  wells  producing  each 
month.  When  monthly  records  are  not  available 
give  data  by  years. 

Gas-well  Data 

19.  Submit  table  giving  list  of  gas  wells  as  of  date  of  acquisition, 

and  showing — 

(a)  Number  or  letter  by  which  each  is  designated. 

(6)  Date  of  begimiing  drilling, 

(c)  Date  of  beginning  production. 

{d)  Date  of  abandonment. 

(e)  Initial  open  flow  capacity. 

(f)  Initial  closed  rock  pressure. 

{g)  Closed  rock  pressure  as  of  date  of  acquisition. 


52  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

Gas-production  Data. 

20.  Submit  table  showing — 

(a)  Gross  production  (of  gas)  by  calendar  years,  from 
beginning  of  production  to  date  of  acquisition, 
with  number  of  wells  producing  each  year. 

(6)  Same  information  for  years  subsequent  to  date  of 
acquisition. 

(c)  Amount  of  money  and  cash  value  of  any  other  con- 

sideration received  each  year  for  production  men- 
tioned in  (a)  and  (6). 

(d)  Average  price  per  thousand  cubic  feet  of  gas,  by  years 

from  beginning  of  production. 

(e)  Total  yield  from  beginning  production  to  date  of  acqui- 

sition, in  cubic  feet. 
(/)    Total  yield  from  beginning  production  to  date,  in  cubic 
feet. 

21.  Production  of  individual  wells  by  calendar  years  for  all 

wells  to  end  of  taxable  year. 

22.  (o)  Average  rock  pressure  in  September  of  each  year  during 

which  production  has  been  maintained. 
(6)  Rock  pressure  of  individual  or  test  wells  on  tract. 
(Answers  should  be  attached  as  a  separate  state- 
ment giving  all  rock  pressures  measured  during  life 
of  the  well  or  property.  The  method  used  in 
measuring  pressures  should  be  mentioned.) 


Physical  Property. 

23.  Does  the  cost  of  property  as  given  in  8  (/)  of  this  schedule 

include  any  amount  for  plant  or  other  physical 
property  or  for  the  value  of  the  land  for  any  other 
purpose  than  that  as  container  of  oil  and  gas? 

24.  If  it  does,  what  amount  is  applicable  solely — 
(a)  To  the  value  of  the  oil  and  gas  contents? 

(h)  To  the  surface  or  agricultural  value  of  the  land  or  its 
value  for  anything  other  than  for  its  oil  and  gas 
contents? 

(c)   To  plant  or  other  physical  property? 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY  53 

25.  Give  general  inventory  as  of  date  of  acquisition  of  the 
physical  property  mentioned  in  24  (c)  with  the 
following  information  regarding  each  type: 
(a)  Year  originally  acquired. 
(&)  Original  cost. 

(c)  Depreciation  sustained  to  date  of  acquisition. 

(d)  Estimated  cost  as  of  date  of  acquisition. 


II.  Schedule  for  the  Valuation  of  Property  as  of  any  Specified  Date. 

Introduction. — In  actually  determining  the  fair  market  value  of 
any  property  as  of  any  specified  date  it  will  be  necessary  in  most 
instances  to  require  very  full  data  regarding  the  property  in  order 
that  no  factors  having  a  bearing  on  the  value  may  be  overlooked. 
The  following  information  as  of  the  specified  date  of  appraisal  will 
usually  be  required  of  the  taxpayer  in  order  to  substantiate  his 
appraisal. 

Note. — "  Date  of  appraisal  "  is  the  specified  date  as  to  which  the  valua- 
tion is  set  up  and  is  not  the  date  on  which  the  appraisal  is  made. 

1.  Description  of  the  property. 

(a)  A  legal  description  of  the  property,  mcluding  its  loca- 
tion in  section  (or  farm),  township,  range,  county, 
and  State. 

(h)  Whether  or  not  the  taxpayer  is  the  sole  owner;  and  if 
not,  his  ownership  interest  therein  and  the  names 
•  and  addresses  and  ownership  interest  of  each  of 

other  joint  owners. 

(c)  Whether  the  property  is  a  leasehold;   if  so,  the  name 

and  address  of  the  lessor  and  lessee. 

(d)  The  date  lease  was  effective. 

(e)  Date  of  expiration. 
(J)   Royalty  rate. 

(g)  Bonds,  either  cash  or  property. 
(h)  Any  unusual  terms  of  lease. 

2.  Date  of  acquisition. — The  date  the  property  was  acquired. 

3.  Manner  of  acquisition  and  cost. 

(a)  The  manner  of  acquisition  of  tlio  pr()i)erty,  whether  l)y 
purchase,  trade,  gift,  etc. 


54  MANUAL   FOR  THE  OIL   AND   GAS   INDUSTRY 

(6)  The  amount  of  the  consideration  paid,  such  as  cash, 
stock,  bonds,  etc.,  and  the  cash  value  of  these,  and 
how  this  cash  value  was  determined. 

4.  Map  of  property. — A  map  of  the  property  on  a  convenient 

scale,  preferably  not  less  than  2  inches  to  the  mile. 

showing  as  of  date  of  appraisal — 
(a)  The  producing,  suspended,  or  abandoned,  and  drilling 

wells,  and 
(6)  The  area  of  the  tract  which  is  considered  producing, 

proven,  highly  probable,  possible,  or  worthless  oil 

or  gas  land. 
In  the  case  of  a  taxpayer  owning  more  than  one  tract  in 

a  single  pool  or  field,  a  field  map  may  be  substituted 

for  maps  of  each  tract,  the  tracts  or  leases  being 

designated  by  letter  or  some  other  symbol. 

5.  Land  data. — A  statement  as  to  the  number  of  acres  con- 

sidered fully  developed,  proven,  highly  probable,  pos- 
sible, or  worthless  oil  or  gas  territory,  including  the 
total  acreage,  and  the  name  and  address  of  the  party 
making  such  classification. 

6.  Well  data. — 

(a)  Information  as  to  the  number  of  wells  producing, 

abandoned,  or  suspended,  drilling  and  the  number 
of  locations  remaining  undrilled  on  proven  terri- 
tory. 

(b)  The  number  and  designation  of  the  oil  or  gas  sands 

proven  on  the  property,  with  their  average  thick- 
ness and  the  average  depth  from  the  surface  of  the 
top  of  each  sand. 

7.  Individual  well  data. — The  following  information  regarding 

the  individual  wells: 
(a)  The  number  of  the  well. 
(6)  Date  began  drilling. 

(c)  Date  began  producing. 

(d)  Date  abandoned. 

(e)  Initial  daily  production. 

8.  Production  data. 

(a)  The  production  of  each  tract  by  calendar  years  for  the 
periods  prior  to  and  subsequent  to  the  date  of 
appraisal. 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY  55 

(6)  The  average  number  of  wells  producing  each  year. 

(c)  The  amount  received  each  year  for  the  production. 

(d)  The  average  price  per  barrel  received  each  year. 

(e)  The  total  production  prior  to  and  subsequent  to  date  of 

appraisal. 

(/)  The  total  amount  received  prior  to  and  subsequent  to 
the  date  of  valuation. 
Where  production  figures  of  individual  wells  are  avail- 
able, give  the  records  for  all  years  from  the  begin- 
ning of  production  to  the  date  of  valuation,  and 
for  the  years  subsequent  thereto.  In  the  case 
of  properties  yielding  production  for  a  period  of 
less  than  two  years,  the  above  data  should  be 
given  by  months  instead  of  years. 
9.  Oil  and  gas  reserves. 

(a)  The  estimated  total  number  of  units  of  oil  or  gas  in 
the  property  as  of  the  date  of  appraisal.  (Many 
operators  are  prone  to  say  it  is  impossible  to  esti- 
mate the  quantity  of  oil  or  gas  under  any  tract — 
obviously  it  is  impossible  to  determine  this  exactly 
but  it  can  be  done  with  reasonable  accuracy  in  most 
instances.) 

(&)  How  this  estimate  was  made. 

(c)  The  name  and  address  of  the  party  making  the 
estimate  and  a  copy  or  resume  of  his  report. 

10.  Specific  gravity. 

(a)  The  range  in  specific  gravity  of  the  oil  recovered. 

(6)  The  average  specific  gravity  of  the  oil  delivered,  and,  if 
more  than  one  grade  is  delivered,  the  percentage  of 
each  delivered  during  the  year  covered  by  the 
appraisal. 

11.  Casing-head  gas. — The  followmg  information  by  months: 
(a)  The  quantity,  in  thousands  of  cubic  feet,  produced 

prior  to  and  subsequent  to  the  date  of  appraisal. 
(6)  The  number  of  wells  producing  this  gas. 
(c)   The  amount  received  for  the  gas,  if  such  was  sold 

direct. 
{d)  The  quantity,  in  gallons,  of  gasoline  made. 
(e)   The  amount  received  for  this  gasoline. 
(/)  The  average  price  per  gallon. 


66  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

(g)  The  production  of  oil  by  months  for  the  wells  yielding 
the  gas  covered  by  this  paragraph. 

12.  Gas  properties. — In  the  case  of  gas  properties  the  well  data 

should  include: 
(a)  The  number  of  each  well. 
(h)  Date  began  drilhng. 

(c)  Date  began  producing. 

(d)  Date  abandoned. 

(e)  Initial  daily  capacity. 

(J)   The  initial  closed  rock  pressure. 
(g)  Present  closed  rock  pressure. 

The  production  data  are  to  be  given  by  calendar  years 
prior  to  and  subsequent  to  date  of  appraisal, 
(a)  Number  of  wells  producing. 

(6)  The  value  of  the  product  and  the  average  price  per 
thousand  feet. 

(c)  The  total  yield  (1)  prior  to  and  (2)  subsequent  to  the 

date  of  appraisal. 

(d)  The  gross  production  of  individual  wells  by  calendar 

years  to  date. 

(e)  The  average  rock  pressure  during  September  of  each 

year  during  which  production  has  been  maintained, 
and  as  many  records  as  possible  of  the  rock  pres- 
sure of  individual  or  test  wells. 

Direct  Methods  of  Determining  Value. 

13.  The  points  to  be  considered  directly  in  the  establishment  of 

a  fair  market  value  must  include  the  method  by  which 

this  value  was  ascertained, 
(a)  Whether  established  by  cost. 

(6)  By  comparison  with  values  established  by  actual  sales 
of  similar  properties. 

(c)  By  appraisal. 

(d)  By  assessed  value. 

(e)  By  any  other  method. 

14.  If  the  value  is  based  upon  the  values  of  other  properties,  as 

established  through  the  transfer  of  the  properties, 
details  regarding  each  transaction  will  be  necessary. 
Furthermore,  it  will  be  advisable  to  give  information 


MANUAL   FOR  THE  OIL   AND   GAS   INDUSTRY  57 

regarding  any  bona  fide  transactions  in  oil  or  gas  prop- 
erties in  the  region  of  the  tract  under  appraisal  about 
which  the  taxpayer  is  able  to  obtain  data,  this  informa- 
tion to  include  as  rnany  of  the  items  called  for  in  con- 
nection with  the  valuation  of  the  property  itself  as  it 
is  possible  to  secure. 

15.  If  the  value  is  established  by  appraisal  give — 

(a)  The  name  and  address  of  the  party  making  the  ap- 
praisal. 

(6)  His  connection,  if  any,  with  the  taxpayer  or  with  any 
of  his  associates  or  associated  companies. 

(c)  The  date  of  making  the  appraisal. 

(d)  A  copy  of  the  appraisal  or  a  resume. 

16.  If  the  value  is  established  by  assessed  valuation,  the  fol- 

lowing should  be  given: 
(a)  Name  and  address  of  official  making  the  assessment. 
(6)  Whether  it  was  assessed  at  its  actual  cash  value  or  at  a 
portion  of  its  cash  value. 

(c)  What  its  total  assessed  valuation  was  in  the  year  in 

which  the  appraisal  was  made. 

(d)  What  portion  of  the  assessed  valuation  represents  real 

property? 

(e)  What  portion  represents  personal  property. 

(/)  What  portion  of  the  assessed  value  of  the  real  property 
represents  oil  or  gas  in  the  ground? 

17.  If  the  values  are  established  by  any  other  method  than  the 

above  a  full  description  of  the  method  used  and  con- 
clusions reached  should  be  given. 

18.  If  the  valuation  of  the  property  includes  any  amount  for 

plant  or  other  physical  property,  or  for  the  surface  or 
agricultural  value  of  the  land,  or  the  value  of  the  land 
for  any  other  purpose  than  as  a  container  of  oil  and  gas 
the  value  should  be  segregated  under  the  headings: 

(a)  Value  of  oil  and  gas  contents. 

(6)  Values  for  anything  other  than  for  oil  and  gas  contents. 

(c)   Value  of  plant  or  other  physical  equipment. 

19.  An  inventory  of  the  physical  equipment  as  of  the  date  of 

appraisal  should  be  given,  together  with  the  following 
information  regarding  each  type  of  property: 
(o)  When  the  equipment  was  first  used. 


58  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

(6)  Its  cost. 

(c)  Its  total  depreciation  up  to  the  date  of  appraisal. 

(d)  Its  value  as  of  the  date  of  appraisal. 

(e)  Depreciation  by  calendar  years  for  each  year  subse- 

quent to  the  date  of  appraisal. 
The  classification  of  physical  equipnient  will  be  found 
under  the  chapter  on  depreciation,  page  78  of  this 
Manual. 

Indirect  Methods  of  Determining  Value. 

20.  The  book  value  of  the  total  assets  on  the  date  of  valuation 

exclusive  of  oil  or  gas  in  the  ground. 

21.  (a)  The  number,  par  value,  and  cash  value  of  the  shares  of 

capital  stock  issued  and  outstanding  on  the  date 
of  appraisal. 

(6)  Whether  or  not  these  outstanding  shares  were  fully 
paid. 

(c)  Information  as  to  what  stock  exchange  or  "  curb  " 
market  the  stock  or  bonds  were  listed  on,  or  dealt 
in,  on  or  about  the  date  of  appraisal;  or  if  the 
stocks  were  not  quoted  publicly,  particulars  re- 
garding private  transactions  in  the  stock  or  bonds 
on  or  about  the  date  of  appraisal. 

22.  Total  permanent  indebtedness  classified  as  bonds,  notes, 

contracts,  etc.,  and  what  the  quoted  value  of  these 
securities  was  or  any  particulars  regarding  public 
or  private  transactions  which  would  tend  to  estab- 
lish their  value. 

23.  The  prevailing  average  royalty  rates  stipulated  in  leases 

taken  within  a  year  of  the  date  of  appraisal  in  the 
district  in  which  the  property  is  located. 

24.  Copy  of  the  report  of  the  stockholders  of  the  company  for 

each  of  the  fiscal  years  preceding  and  following  the 
date  of  appraisal. 

25.  So  far  as  known,  the  names  of  the  parties  to  any  litigation 

in  which  the  value  of  the  oil  and /or  gas  properties  in 
the  particular  region  of  the  property  under  discussion, 
or  of  a  partnership  interest  or  other  interest  therein, 
or  of  stock  in  a  corporation  owning  or  operating  the 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY  59 

same,  was  involved;  also,  the  name  of  the  court  or 
courts  in  which  such  litigation  was  conducted. 

26.  If  the  value  of  the  oil  and/or  gas  wells  in  the  particular 

region  of  the  property,  or  of  any  interest  or  stock 
therein  has  been  involved  in  any  partnership  account- 
ing known,  a  statement  regarding  such  accounting 
should  be  given. 

27.  If  anyone  interested  in  the  oil  and/or  gas  wells  in  the  par- 

ticular region  of  the  property  under  discussion  or  as 
owner,  operator,  or  member  of  a  partnership,  or  stock- 
holder in  a  corporation  owning  or  operating  the  same 
died  on  or  about  the  date  of  appraisal,  give  the  name, 
number  of  shares  held,  the  approximate  date  of  death, 
the  residence  at  time  of  death,  and  the  name  and  loca- 
tion of  the  court  in  which  the  estate  was  administered, 
and  the  name  and  address  of  the  administrator. 

28.  In  addition  to  the  above  the  taxpayer  is  requested  to  sub- 

mit any  other  evidence,  facts,  statements,  etc.,  which 
he  desires  to  have  considered  in  the  determination  of 
the  value  as  of  the  date  of  appraisal. 

///.  Schedule  for  Proof  of  Discovery 

Introduction. — In  order  to  prove  to  the  satisfaction  of  the  Com- 
missioner that  a  bona  fide  discovery  of  oil  or  gas  in  commercial 
quantities  has  been  made,  the  taxpayer  will  be  required,  among 
other  things,  to  submit  the  following,  under  oath: 
1.  Description  of  the  property. 

(a)  A  legal  description  of  the  property,  including  its  loca- 
tion in  section  (or  farm),  township,  range,  county, 
and  State. 
(6)  Whether  or  not  the  taxpayer  is  the  sole  owner,  and  if 
not,  his  ownership  interest  therein,  and  the  names 
and  addresses  and  ownership  interest  of  each  of 
the  other  joint  owners. 

(c)  Whether  the  property  is  a  leasehold;   if  so,  the  name 

and  address  of  the  lessor  and  lessee. 

(d)  The  date  lease  was  effective. 

(e)  Date  of  expiration. 
(/)   Royalty  rate. 


60  MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY 

(g)  Bonus,  either  cash  or  property. 
(h)  Any  unusual  terms  of  lease. 

2.  Date  of  acquisition. 

3.  The  location  of  the  nearest  producing  well  to  the  discovery 

well  on  the  date  discovery  is  claimed. 

4.  Map  of  property. — A  map  of  the  property  on  a  convenient 

scale,  preferably  not  less  than  2  inches  to  the  mile, 
showing,  as  of  the  date  of  discovery, 
(a)  The  location  of  the  tract  and  of  the  discovery  well  in 

question  and  in  addition  the  development  in  the 

field  for  a  radius  of  approximately  3  miles  from  the 

well  in  question; 
(6)  The  producing,  suspended  or  abandoned  and  drilling 

wells;  and 
(c)   The  areas  which  are  considered  producing,  p:oven, 

highly  probable,  possible,  or  worthless  oil  or  gas 

land. 

5.  A  certified  copy  of  the  log  of  the  discovery  well,  showing: 

(a)  The  location. 

(b)  Date  drilling  began,  date  of  completion  and  the  begin- 

ning of  production. 

(c)  The  formations  penetrated;    the  oil,  gas,  and  water 

sands  penetrated;  the  casing  record,  including 
the  record  of  perforation  and  any  other  informa- 
tion tending  to  show  the  condition  of  the  well  and 
the  location  of  the  sand  of  sands  from  wliich  the 
oil  or  gas  came  on  the  date  the  discovery  was 
claimed. 

6.  The  logs  of  enough  other  wells  drilled  prior  to  the  date  of 

the  completion  of  the  discovery  in  the  vicinity  of  the 
discovery  well  to  convince  the  Comniissioner  that  the 
pool, field,  structure,  sand,  or  zone,  discovery  of  which  is 
claimed,  was  not  known  prior  to  the  so-called  discovery. 

7.  A  sworn  record  clearly  proving  the  commercial  productivity 

of  the  discovery  well.  This  record  must  cover  a 
period  of  not  less  than  30  days  and,  if  possible,  should 
include  the  production  of  the  entire  period  by  months 
from  the  date  of  discovery  to  the  end  of  the  first  year. 

8.  In  the  case  of  the  discovery  being  made  within  3  miles  of 

producing  wells,  the  production  data  from  enough 


MANUAL   FOR  THE  OIL  AND   GAS  INDUSTRY  61 

wells  within  this  area  to  indicate  the  average  produc- 
tivity of  the  wells  drilled  prior  to  the  date  of  drilhng 
the  discovery  well : 

9.  The  specific  gravity  of: 

(a)  The  oil  recovered  from  the  discovery  well. 
(6)  Oil  produced  by  adjacent  wells  which  were  producing 
at  the  time  of  the  drilling  of  the  discovery  well. 

10.  The  following  information  regarding  wells  drilled  on  the 

same  tract  or  lease  as  the  discovery  well  prior  to  and 
subsequent  to  the  date  of  the  disco veiy : 

(a)  Number  of  well. 

(6)  Date  of  beginning  drilling. 

(c)  Date  of  beginning  production. 

(d)  Date  abandoned. 

(e)  Initial  daily  production. 

And  in  the  case  of  wells  drilled  prior  to  the  date  of 
discovery — 

(/)  Copy,  of  the  log  of  the  well,  including  the  formation 
penetrated. 

(g)  The  casing  record  and  any  other  information  tending 
to  show  the  condition  of  the  well  on  the  date  dis- 
covery was  claimed  in  the  discovery  well. 

11.  Any  other  evidence,   facts,   statements,   etc.,   which  the 

taxpayer  desires  to  have  considered  as  proving  that 
the  so-called  discovery  is  bona  fide  and  that  the  pool, 
field  structure,  sand,  or  zone,  discovery  of  which  is 
claimed,  was  not  known  prior  to  the  date  of  discovery. 

IV.  Schedule  for  Depletion. 

With  respect  to  each  property  producing  oil  and/or  gas  during 
the  taxable  year  for  which  the  return  under  consideration  was  filed 
give  the  following  facts : 

1.  Description  of  property. 

2.  Value  (exclusive  of  physical  properties)  as  of  March  1,  1913, 

or  its  cost  if  acquired  subsequent  to  that  date. 

3.  Estimated  quantity  of  oil  and/or  gas  in  ground  as  of 

March  1,  1913,  or  at  date  of  acquisition  if  secured 
subsequent  to  March  1,  1913. 

4.  Make  tabulation  showing: 


62  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

(a)  Capital  sum  returnable  through  depletion  at  begin- 

ning of  year. 

(b)  Capital   returnable   through   depletion   added   during 

year. 

(c)  Total  capital  sum  against  which  depletion  for  year  is 

chargeable  ((a)  plus  (6)). 

(d)  Estimated  quantity  of  recoverable  crude  oil  in  ground 

at  beginning  of  year,  in  barrels  of  42  gallons. 

(e)  Production  for  year  in  barrels  of  42  gallons. 

(/)   Unit  cost  of  recoverable  product  ((c)  divided  by  (d)). 
(g)  Amount  of  depletion  sustained  during  year  ((/)  mul- 
tiplied by  (e)). 

V.  Schedule  for  Depreciation. 

With  respect  to  each  tract  on  which  there  is  physical  property 
mentioned  in  the  return  under  consideration,  give  the  following 
facts : 

1.  Description  of  property. 

2.  Value  of  physical  properties  as  of  March  1,  1913,  or  their 

cost,  if  acquired  subsequent  to  that  date. 

3.  Make  tabulation  showing: 

(a)  Capital  sum  returnable  through  depreciation  at  begin- 
ning of  year. 

(6)  Capital  returnable  through  depreciation  added  during 
year. 

(c)  Total  capital  sum  against  which  depreciation  for  year  is 

chargeable  (a)  plus  (b). 

(d)  Amount  of  depreciation  sustained  during  year. 

VI.  Schedule  for  the  Proof  of  Bona  Fide  Sale. 

Introduction. — To  prove  that  the  sale  consummated  by  the 
taxpayer  is  actually  bona  fide,  he  will  be  required  to  furnish  a 
sworn  statement,  including  the  following: 
1.  Description  of  the  property. 

(a)  A  legal  description  of  the  property,  including  its  loca- 
tion in  section  (or  farni),  township,  range,  county, 
and  State. 
(6)  Whether  or  not  the  taxpayer  is  the  sole  owner,  and  if 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY  63 

not,  his  ownership  interest  therein,  and  the  names 
and  addresses  and  ownership  interest  of  each  of 
the  other  joint  owners. 

(c)  Whether  the  property  is  a  leasehold;   if  so,  the  name 

and  address  of  the  lessor  and  of  the  lessee. 

(d)  The  date  lease  was  effective. 

(e)  Date  of  expiration. 
(/)   Royalty  rate. 

(g)  Bonus,  either  cash  or  property. 
(h)  Any  unusual  terms  of  lease. 

2.  Date  of  disposal  of  property. 

3.  Manner  of  disposal  of  the  property. — Whether  by  sale,  trade 

gift,  etc. 

4.  (a)  The  amount  received  in  cash,  stock,  bonds,  and  other 

considerations. 
(6)  The  par  value  of  the   stock,   bonds,    or   other   con- 
siderations. 

Note. — If  the  "unit-cost"  method  of  computing  depletion  was  not  used 
in  computing  the  depletion  allowance  for  the  various  years  mentioned  in  the 
above  table,  state  what  method  was  used  in  calculating  the  depletion,  and 
give  a  complete  resume  of  the  calculations,  so  that  the  Commissioner  may  arrive 
at  an  intelligent  conclusion  as  to  whether  or  not  the  depletion  allowance 
claimed  for  the  year  was  equitable  and  based  on  the  actual  production  of 
that  year. 

(c)  The  actual  cash  value  of  the  stock,  bonds,  or  other 

considerations  on  the  date  of  disposal  of  the 
property. 

(d)  How  these  cash  values  were  established. 

(e)  The  name  and  address  of  the  party  determining  or 

establisliing  these  values. 

5.  Total  cash  value  of  all  considerations  received  by  the  tax- 

payer for  the  property. 

6.  (a)  The  name  and  address  of  the  party  to  whom  the  prop- 

erty was  transferred. 
(b)  The  connection,  business  or  other,  if  any,  between 
parties  to  the  transfer. 

7.  The  taxpayer  disposing  of  the  property  will  be  required, 

under  oath,  to  state  whether  or  not  the  price  at  which 
the  property  was  sold  was  fixed  for  the  purpose  of  a 
bona  fide  purchase  and  sale  by  which  the  property 


64  MANUAL   FOR  THE  OIL  AND   GAS   INDUSTRY 

passed  to  an  owner  in  fact  as  well  as  in  form  different 
from  the  vendor.  No  fictitious  nor  inflated  sale  price 
will  be  permitted  to  form  the  basis  for  the  price  estab- 
lished for  this  schedule. 
8.  Any  evidence,  facts,  statements,  etc.,  which  the  taxpayer 
desires  to  have  considered  as  a  proof  in  the  determina- 
tion of  the  bona  fide  character  of  the  transaction. 


VII.  Schedule  for  Computation  of  Profits  or  Loss  from  Sale  of 

Capital  Assets. 

With  respect  to  each  property  disposed  of  during  the  year, 
furnish  the  following  information: 

1.  Description  of  property. 

2.  Date  of  disposal  of  property. 

3.  Manner  of  disposal  of  the  property  (sale,  trade,  gift,  etc.). 

4.  Amount  received  in  cash. 

5.  Amount  received  in  stock: 
(a)  Par  value  of  stock. 

(6)  Actual  cash  value  of  stock. 

(c)   How  was  this  cash  value  established? 

6.  Amount  received  in  bonds: 
(a)  Par  value  of  bonds. 

(6)  Actual  cash  value  of  bonds. 

(c)   How  was  this  cash  value  established? 

7.  Amount  received  in  other  considrations : 
(a)  What  were  these  considerations? 

(6)  Actual  cash  value  of  these  considerations. 

(c)  Manner  of  determining  this  cash  value. 

(d)  Name  and  address  of  the  party  determining  this  value. 

8.  Cash  value  of  all  considerations  received  for  property. 

9.  Value  of  property  as  of  March  1,  1913,  or  its  cost  if  acquired 

subsequent  to  that  date. 

10.  Total  of  all  additions  to  capital  returnable  through  deple- 

tion added  subsequent  to  March  1,  1913,  or  subse- 
quent to  date  of  acquisition  if  property  acquired  sub- 
quent  to  March  1,  1913. 

11.  Total  of  all  additions  to  capital  returnable  through  depre- 

ciation added  subsequent  to  March  1,  1913,  or  subse- 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY  65 

quent  to  date  of  acquisition  if  acquired  subsequent  to 
March  1,  1913. 

12.  Gross  value  of  property  as  of  date  of  disposition.     (Total  9, 

10,  and  11.) 

13.  Total  depletion  sustained  during  period  from  March  1,  1913, 

or  from  date  of  acquisition  if  acquired  subsequent  to 
March  1,  1913,  to  date  of  disposition  of  property. 

14.  Total  depreciation  sustained  during  period  from  March  1, 

1913,  to  date  of  disposition  of  property. 

15.  Net  value  of  property  as  of  date  of  disposition  of  property 

(12  less  the  sum  of  13  and  14). 

16.  Profit  or  loss  sustained  from  disposition  of  property  (dif- 

ference between  8  and  15). 

VIII.  Schedule  for  Proving  that  the  Principal  Value  has  been 
Denioristrated  hy  Prospecting  or  Exploration  and  Discovery 
Work  Done  hy  the  Taxpayer. 

Introduction. — In  the  case  of  a  bona  fide  sale  of  oil  or  gas  prop- 
erties it  will  be  necessary,  in  order  to  secure  the  benefits  of  sections 
211b  and  337  of  the  Revenue  Act  of  1918,  which  limits  the  portion 
of  the  surtax  imposed  by  said  act  attril^utable  to  such  sale  to  a 
sum  not  to  exceed  20  per  cent  of  the  selling  price  of  such  property 
or  interest,  to  satisfy  the  commissioner  that  the  principal  value  of 
the  property  has  been  demonstrated  by  prospecting  or  exploration 
and  discovery  work  done  by  the  taxpayer  by  submitting  the  fol- 
lowing among  other  data: 

1.  Description  of  the  property. — 

(a)  A  legal  description  of  the  property,  including  its  loca- 
tion in  section  (or  farm),  township,  range,  county, 
and  State. 
(6)  Whether  or  not  the  taxpayer  is  the  sole  owner,  and  if 
not,  his  ownership  interest  therein,  and  the  names 
and  addresses  and  ownership  interest  of  each  of 
other  joint  owners. 

(c)  Whether  the  property  is  a  leasehold;   if  so,  the  name 

and  address  of  the  lessor  and  lessee. 

(d)  The  date  lease  was  effective. 

(e)  Date  of  expiration. 
(/)   Royalty  rate. 


66  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

(g)  Bonus,  either  cash  or  property. 
(h)  Any  unusual  terms  of  lease. 

2.  The  value  of  the  property  immediately  prior  to  the  date  of 

beginning  the  prospecting  or  exploration  and  discove  y 
work  done  by  the  taxpayer  leading  to  the  discovery 
claimed. — (Tliis  may  be  established  through  filling 
out  Schedule  II  as  of  the  specified  date.) 

3.  The  proof  that  a  discovery  has  been  made. — (To  furnish  this 

proof  the  taxpayer  will  be  required  to  fill  out  Schedule 
III.) 

4.  The  value  of  the  proverty  at  any  specified  data  within  a  rea- 

sonable time  after  the  discovery  was  made. — (This  value 
may  be  estabhshed  by  filling  out  Schedule  II  for  the 
specified  data.) 

5.  Any  evidence,  facts,  statements,  etc.,  which  the  taxpayer 

desires  to  have  considered  as  showing  that  the  prin- 
cipal value  of  the  property  has  been  demonstrated 
by  prospecting  or  exploration  and  discovery  work 
done  by  himself. 


PART  II. 

ESTIMATE  OF  DEPRECIATION  OF  EQUIPMENT  USED  IN 
THE  OIL  AND  GAS  INDUSTRY. 

PREFACE  TO  PART  II. 

This  chapter  is  a  condensation  and  summarization  of  the  con- 
clusions of  a  committee  appointed  to  investigate  and  standardize 
depreciation  allowances  in  the  case  of  oil  and  gas  properties.  It  is 
prepared  to  meet  the  questions  of  taxpayers  as  to  what  is  a  reason- 
able allowance  for  depreciation  in  the  case  of  oil  and  gas  properties. 
In  preparing  the  figures  of  rates  of  depreciation,  reports  from  some 
of  the  larger  companies  were  reviewed  and  the  opinions  of  various 
individuals  closely  associated  with  the  industry  were  obtained. 
Over  5  '  companies  and  individuals  were  canvassed  in  this  work 
and  th?  conclusions  were  reached  by  considering  the  company 
practices  as  well  as  taking  into  account  the  experience  of  the 
members  of  the  committee  and  the  precedents  and  practices  of 
the  Treasury  Department. 

The  percentages  and  tables  included  in  this  paper  are  intended 
as  a  suggestion  for  the  guidance  of  the  taxpayer  in  calculating  his 
just  tax.  The  percentages  are  neither  maximum  nor  minimum 
rates.  They  are  not  to  he  applied  indiscriminately  to  specific  prop- 
erty, and  the  Internal  Revenue  Bureau  is  in  no  way  committed  to 
accept  allowances  based  upon  them.  Every  claim  for  deduction 
must  be  accompanied  by  a  detailed  statement  of  the  facts  upon 
which  such  claim  is  based. 

Each  class  of  equipment  is  shown  in  detail  and  as  a  class,  with 
the  suggestion  that  an  average  life  of  the  class  be  used  rather  than 
going  into  the  details  of  every  part. 

The  average  years  of  useful  life  of  the  various  classes  is  shown 
in  the  summary  sheet  and  a  suggestion  for  charging  out  annual 
percentages  to  conform  to  the  depreciation  as  it  actually  occurs. 

It  must  be  borne  in  mind  that  it  is  not  possible  to  make  stand- 
ard rules  or  formula  to  cover  all  conditions  in  this  business. 

Although  different  rates  may  reasonably  be  applied  in  different 

67 


68  MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY 

parts  of  the  country,  the  average  rates  for  each  locality  have  not 
been  included  here,  as  it  is  believed  that  the  variation  of  such  rates 
from  the  general  average  is  so  slight  as  to  be  practically  negligible 
in  most  instances.  Whenever  the  life  of  the  property  is  materially 
shorter  than  that  called  for  in  this  schedule,  a  special  rate  may  be 
claimed,  or  the  difference  may  be  made  up  by  replacements  charge- 
able to  the  maintenance  accounts.  In  the  case  of  some  of  the  Gulf 
coast  districts,  portions  of  the  pipe  lines  are  eaten  out  in  five  or  six 
years.  These  repairs  are  rightly  a  replacement  and  chargeable  to 
maintenance  or  operating  accounts. 

Depreciation  deductions  are  to  be  charged  to  a  reserve  fund,  and 
are  in  addition  to  any  regular  charge  for  repairs  and  operating 
maintenance. 

No  consideration  has  been  given  exceptional  cases  where 
premature  failure  of  supply  or  market  may  materially  reduce  the 
given  life  of  the  facility.  Such  cases  are  necessarily  exceptional 
and  will  receive  special  consideration,  as  provided  for  in  the 
regulations.     (See  Regulation  45,  Art.  225.) 

CLASS  A.  NO.  1.— DRILLING  EQUIPMENT. 

This  includes  engines,  boilers,  rig  irons,  and  portable  derricks. 
It  is  recommended  that  four  years'  life  be  allowed  to  equip- 
ment as  a  whole,  depreciated  at  the  following  rate 

Per  Cent. 

First  year 40 

Second  year 25 

Third  year 15 

Fourth  Year 10 

90 
Salvage 10 

100 

Permanent  derricks,  rig  irons,  boilers,  and  engines  left  at  the 
well  are  included  under  "  Well  equipment." 

Drilling  tools  (cable  and  rotary),  and  fishing  tools  are  included 
under  "  Tools  "—Class  A-No.  5. 

CLASS  A,  NO.  2.— WELL  EQUIPMENT. 

As  most  equipment  of  a  producing  well  has  no  separate  value 
apart  from  the  well,  it  is  suggested  that  all  wells  and  their  equip- 


MANUAL   FOR  THE  OIL  AND   GAS   INDUSTRY 


69 


merit  be  depreciated  at  the  same  rate  as  the  wells  are  depleted, 
using  the  same  curve  rate  for  both  or  where  the  life  of  the  physical 
equipment  is  greater  than  the  life  of  the  deposit,  then  the  depre- 
ciation rate  of  the  physical  equipment  will  be  governed  by  the 
reasonable  expectation  of  the  life  of  the  deposit. 

When  the  life  of  the  equipment  is  shorter  than  the  life  of  the 
well,  replaced  equipment  should  be  charged  against  maintenance 
and  operation. 

This  method  proved  satisfactory  in  the  appraisement  of  the 
Independent  Oil  Producers  Agency  of  California,  embracing 
some  130  companies,  and  is  generally  acceptable  to  all  operators 
who  have  been  consulted  in  the  matter. 


CLASS  A,  NO.  3.— DEHYDRATORS. 

These  are  either  of  electric,  pipe,  or  tank  type.  The  life  of  the 
pipe  and  tank  dehydrators  is  very  erratic  as  these  burn  out  quickly 
with  practically  no  salvage.  It  is  recommended  that  this  type  of 
equipment  have  a  straight  line  depreciation  as  follows: 


Depreciation 
per  Year. 


Electric 
Pipe .  .  . 
Tank . . 


Per  Cent. 

20 
50 
50 


CLASS  A,  NO.  4.— TANKS. 
The  following  depreciation  rate  for  tanks  is  recommended : 

Per  Cent. 


Steel,  5,000  to  55,000  barrels 

Steel,  2,500  to  5,000  barrels 

G.  I.,  500  to  2,500  barrels 

G.  I.,  less  than  500  barrels 

Wood 

Movable  tanks: 

G.  I.,  500  to  2,500  barrels 

G.  I.,  less  than  500  barrels 

G.  L,  water  tanks,  500  to  2,.')()0  barrels. 

G.  I.,  water  tanks,  less  than  500  barrels 


12^ 

20 

lU 
16| 
12J 
20 


70  MANUAL   FOR  THE  OIL  AND   GAS   INDUSTRY 

These  results  may  be  used  for  all  classes  of  service — that  is,  oil 
producing,  refineries,  etc. 

CLASS  A,  NO.  5.— TOOLS. 

This  includes  standard,  rotary,  and  fishing  tools.  While 
rotary  equipment  may  be  shorter  lived,  it  is,  in  general,  offset  by 
the  standard  tool  equipment  which  will  have  a  life  of  at  least  four 
years  in  many  cases. 

Owing  to  the  excessive  wear  and  tear  and  losses  on  such  equip- 
ment an  average  life  of  three  years  is  recommended,  using  an 
annual  depreciation  of  33^  per  cent. 

CLASS  A,  NO.  6.— TRANSPORTATION  EQUIPMENT. 

All  transportation  equipment,  such  as  motor  trucks,  autos, 
wagons,  horses,  and  harness,  can  be  placed  at  a  three-year  life  or 
an  annual  depreciation  of  33|  per  cent. 

In  fact,  the  average  life  of  automobiles  is  less  than  three  years. 
The  percentages  of  cost  for  horses,  harness,  and  wagons  is  such 
that  the  whole  can  be  made  one  class  with  three  years'  life  and 
consider  no  salvage. 

CLASS  A,  NO.  7.— WATER  PLANTS. 

Considering  the  water  well,  pump,  steam  power,  gas  and  oil 
power,  electric  power  as  a  class,  they  may  be  given  a  useful  life  of 
approximately  10  years,  which  allows  a  straight  depreciation  of 
10  per  cent. 

CLASS  A,  NO.  8.— ELECTRIC  EQUIPMENT. 

In  considering  electrical  equipment,  one  may  include  the 
separate  items  of  generators,  various  size  motors,  transformers, 
wiring  (both  indoor  and  outdoor),  power  lines,  and  switchboard. 

As  oil-well  niotors  are  not  suitable  for  other  uses  and  as  the 
class  of  wiring  usually  done  on  leases  is  not  up  to  utility  company 
standards,  it  is  recommended  that  a  combined  life  on  electric 
equipment  be  placed  at  10  years,  or  an  annual  depreciation  of  10 
per  cent. 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY  71 

CLASS  A,  NO.  9.— MACHINE  SHOP. 

In  covering  machine  shop  there  is  included  wood  buildings, 
power  tools,  blacksmith  tools,  small  hand  tools,  shafting,  and  shop 
power,  which  will,  on  an  average,  have  a  seven-year  life  or  a  depre- 
ciation rate  of  14t  per  cent.  The  smaller  hand  tools,  of  course, 
may  have  a  life  of  not  more  than  two  years,  but  their  cost  is  not 
important  and  the  depreciation  rate  is  lowered  by  the  longer  life 
of  more  expensive  items,  such  as  power  tools,  wood  buildings, 
shafting,  and  shop  power. 

CLASS  A,  NO.  10.— BUILDINGS. 

Buildings  are  grouped  into  four  general  classes: 

No.  1.  Wood,  which  includes  small  dwellings,  small  outhouses, 
small  warehouses,  small  power  plants,  and  small  platforms  which 
are  built  on  the  ground.  These  have  an  average  life  of  10  years, 
which  allows  a  depreciation  rate  of  10  per  cent. 

No.  2.  Frame  buildings,  placed  on  brick  or  concrete  founda- 
tion with  siding  and  shingle  or  patent  roof-painted,  have  an  aver- 
age life  of  15  years  or  a  straight  line  depreciation  of  6|  per  cent. 

No.  3.  Corrugated  iron  siding,  renewable,  has  a  life  of  six  years 
or  a  depreciation  rate  of  16f  per  cent 

No.  4.  Concrete,  brick,  and  steel  frame  have  an  average  life 
of  25  years  or  an  annual  depreciation  rate  of  4  per  cent. 

The  permanent  buildings  may  outlast  the  remainder  of  the 
plant;  hence,  no  salvage  value.  Gulf  Coast  fields  may  claim 
shorter  life  on  account  of  salt-air  conditions. 

CLASS  B.— PIPE  LINES. 

Pipe  lines  are  subdivided  into  main  line,  pump  stations  (which 
include  all  equipment  such  as  engines,  pumps,  l)oilers,  etc.),  auxili- 
ary equipment,  buildings,  telephone  and  telegraph,  and  tenninal 
facilities. 

It  is  recommended  that — 

Mains  6  inches  in  diameter  or  over  be  based  on  a  20-5^ear  life 
or  an  annual  depreciation  of  5  per  cent. 

Mains  under  6  inches  diameter  be  based  on  a  IG-ycai  life  or  an 
annual  depreciation  of  61  per  cent. 

Gathering  lines  be  based  on  a  10-year  life  or  an  animal  depre- 
ciation of  10  per  cent,  with  a  salvage  of  10  per  cent. 


72 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY 


Pump  stations,  including  all  equipment,  telephone  lines,  and 
terminal  facilities  a  life  of  10  years,  or  an  annual  depreciation  of  10 
per  cent. 

These  conclusions  were  reached  after  carefully  considering 
detailed  data  in  which  it  was  decided  that  pipe  lines  could  be 
grouped  into  the  subdivisions  given  above. 

The  subject  of  electrolysis  in  pipe  lines  has  been  investigated 
and  the  losses  have  proved  to  be  very  small  and  negligible  in  com- 
parison with  the  amounts  invested,  so  far  as  making  any  special 
allowances  in  depreciation. 

Below  is  given  the  result  of  a  pipe  line  220  miles  long,  having 
16  stations  and  costing  $3,906,668. 


Right  of  way 

Ditching 

Pipe 

Steel  storage 

Buildings 

Total 

Machinery: 

Pumps 

Boiler 

Heaters 

Miscellaneous  (freight,  etc.) 

Total 

Wirirg 

Fittings 

Commissary 

Telephone  lines 

Spurs,  loading  racks,  etc 

Sundries  (tools,  paints,  water  wells,  etc.,  superin- 
tendence supervision) 

Total 

Grand  total  cost 


$83,176 
497,358 
1,323,901 
426,047 
246,651 


2,577,133 


260,108 

136,356 

30,341 

88,937 


515,742 


8,060 

151,725 

270,782 

85,905 

14,276 

283,045 


1,329,535 


3,906,668 


Per  Cent  of  Total 
Life  in — 


Cost. 


2.2 
12.7 
33.9 
10.9 

6.3 


6.7 
3.5 


.2 
3.9 
6.9 
2.2 

.4 

7.2 


100.1 


Years. 


20 
*20 
20 
20 
20 


Weight. 


0.44 
2.54 
6.78 
2.18 
1.26 


.94 
.35 
.08 
.18 


.02 

.27 
.69 
.22 
.02 

.36 


116.33 


*  Same  as  pipe. 


t  Average  life. 


CLASS  C— TANK  CARS. 
This  class  of  equipment  is  of  very  stable  construction,  and  it 
would  appear  that  the  maximum  20-year  life  can  be  accorded  and 
a  5  per  cent  per  annum  depreciation  established. 


MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY 


73 


CLASS  C— REFINERIES. 

In  order  to  arrive  at  a  depreciation  figure  for  the  refinery  as  a 
whole,  it  is  necessary  to  determine  the  relative  investment  in  each 
item  of  equipment  as  compared  to  total  investment.  The  various 
items  have  been  grouped  into  classes  that  have  about  the  same  rate 
of  depreciation,  and  the  depreciation  for  the  whole  plant  calculated 
by  multiplying  each  item  by  its  rate  of  depreciation. 

Refineries  were  divided  into  two  classes,  skimming  plants  and 
complete  refineries — that  is,  refineries  equipped  with  lubricating 
plants  (but  not  having  cracking  plants).  Figures  for  relative 
investment  in  each  class  of  equipment  were  obtained  from  reports 
on  valuation  of  refineries  and  from  our  own  estimates. 


CALCULATED  DEPRECIATION  FOR  WHOLE  REFINERY. 

(a)  Complete  Refinery. 


Per  Cent 
of  Total 
Invest- 
ment. 


Rate  of 
Depre- 
ciation. 


Product. 


Equipment:  )  Per  Cent. 

Distilling  equipment   (stills,  condensers,  agitatorS: 

etc.) 25 

Power  plant  (boilers,  engines,  electrical  equipment 

etc.) 15 

Buildings 10 

Storage  (all  kinds) 25 

Pipes  and  fittings 10 

Lubricating  plant  (filters,  presses,  chillers,  grease  plant, 

etc.) 

Miscellaneous     (   .   .   .  loading    racks,     machine    shop, 

laboratory,  etc.) 


Depreciation  on  refinery  as  a  whole. 


Per  Cent. 
15 

10 

5 

8 
12 

10 

10 


Per  Cent. 

3.8 

1.5 

.5 

2.0 

1.2 

1.0 

.5 


10. 


(6)  Skimming  Plant. 


Distilling  equipment. 

Power  plant 

Buildings 

Storage 

Pipes  and  fittings.  . .  . 
Miscellaneous 


Depreciation  on  refinery  us  a  whole. 


Per  Cent. 
35 
10 

5 
35 
10 

5 


Per  Cent. 
15 
10 
10 
8 
12 
10 


Per  Cent. 
5.3 
1.0 

.5 
2.8 
1.2 

.5 


11.3 


74 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY 


Refineries  can  also  be  classed  according  to  their  location  into 
three  general  classes  and  should  be  given  rates  of  depreciation 
accordingly.  The  three  classes  and  suggested  relative  depreciation 
are  as  follows: 


Well-constructed  refinery  plants  located  on  the  Atlantic  coast  or  Gulf 
coast  or  at  points  that  are  assured  of  a  supply  so  long  as  there  is 
production  east  of  the  Rocky  Mountains  or  from  Mexico 

Refinery  plants  of  good  construction  located  on  trunk  pipe  lines  or 
where  a  supply  of  crude  is  assured  for  several  years 

Skimming  plants  and  small  refineries  of  poor  construction  or  located 
at  points  where  the  supply  of  crude  is  not  assured  for  a  long 
period  of  t  ime 


Deprecia- 
tion Rate. 


Per  Cent. 
5 


10 


161 


It  is  suggested  that  the  last  named  be  depreciated  according  to 
the  decline  curve  of  the  oil  field  supplying  the  oil. 

The  estimates  of  the  total  depreciation  were  based  on  what 
was  considered  the  normal  life  of  the  plant,  and  no  conditions 
that  were  purely  local  were  taken  into  consideration.  However, 
in  making  any  depreciation  charge  the  relation  of  the  location 
must  be  taken  into  account.  Such  things  as  the  supply  of  raw 
material,  removal  of  market,  climatic  conditions,  soil  conditions, 
and  the  nature  of  the  raw  material  are  points  brought  out  by  local 
conditions. 

Plants  situated  on  pipe-line  terminals  and  those  on  the  sea- 
board that  can  be  fed  by  tankers  and  pipe  lines  have  an  advanta- 
geous position.  Plants  in  the  midst  of  an  oil  field  relying  solely 
on  that  field  for  crude  supply  have  a  length  of  life  depending  on 
the  life  of  the  field.  Plants  on  pipe  lines  controlled  completely 
or  in  part  by  the  company  owning  the  plant  are  in  much  better 
shape  than  those  dependent  on  a  rival  company  for  their  supply  of 
crude. 

A  plant  is  subject  to  the  removal  of  its  market  in  whole  or  in 
part  when  it  is  situated  a  great  distance  from  that  market  and  is 
confronted  with  a  new  plant  or  competitor  adjacent  to  the  market 
that  is  able  to  undersell  the  products  of  the  distant  plant.  The 
foreign  niarket  may  be  completely  removed  through  the  growth  of 
new  oil  fields  and  competitive  tariff  conditions. 

Any  abnormal  rate  of  depreciation  due  to  the  chemical  nature 
of  the  soil  causing  ironwork  to  deteriorate  rapidly  must  be  con- 


MANUAL  FOR   THE   OIL  AND   GAS  INDUSTRY 


75 


sidered.  Conditions  of  high  humidity  shorten  the  Hfe  of  ironwork 
and  brickwork. 

High  sulphur  crudes  cause  stills  and  condensers  to  deteri- 
orate rapidly.  Crudes  containing  salt,  other  solid  or  colloidal 
matter  and  those  carrying  a  high  content  of  water  and  foreign 
matter  cause  a  shorter  life  for  general  refinery  equipment. 

An  agreement  must  be  reached  between  the  Treasury  Depart- 
ment and  the  refiners  in  cases  for  special  districts  as  to  just  how 
much  extra  depreciation  they  should  be  allowed  for  a  condition 
that  is  peculiar  to  their  territory. 

The  total  general  depreciation  that  is  allowed  takes  in  the  skim- 
ming plants  and  so-called  complete  refineries  that  have  a  lubri- 
cating plant.  For  plants  that  have  a  complete  refinery  and  in 
addition  cracking  plant,  certain  extra  depreciation  charges  must 
be  allowed.  In  many  cases  the  cracking  plant  is  as  much  as  one- 
tenth  the  total  plant  investment  and  should  be  given  a  shorter  life 
than  the  average  plant's  life. 

CLASS  D.— SALES  OR  MARKETING  EQUIPMENT. 

Sales  or  marketing  equipment  is  summarized  in  the  following 
table : 


Life  for 
Deprecia- 
tion. 


Annnual 
Deprecia- 
tion Hate. 


Tankers:  Where  such  have  been  bought  or  built  during  the  war 
period,  that  such  cost  be  written  off  to  $125  per  D.  W.  ton  and 
at  that  rate . 

Barges,  harbor  tugs,  or  other  small  floating  equipment 

Filling  stations: 

(1)  Ordinary  wood  or  corrugated  construction 

(2)  Brick  and  concrete,  or  extraordinary  construction 

Distributing  stations 

Tank  wagons: 

Motor  type 

Horse  type 

Steel  barrels 

Tracks  and  switches 


Years. 

20 

5 

5 
10 
10 

4 
6 

7 
8 


Per  Cent. 

5 

20 

20 
10 
10 

25 
161 
14? 
12J 


In  considering  depreciation  on  filling  stations  the  factor  to  be 
given  and  most  consideration  is  location.  The  normal  life  of 
equipment  and  buildings  is  at  least  10  years,  but  unless  the  station 
is  favorably  situated  it  may  only  last  2  or  3  years. 

Note. — Filling   stations   arc   divided   into   two   classes:     (a) 


76  MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY 

Stations  that  have  temporary  wooden  or  corrugated  iron  buildings; 
and  (b)  stations  that  have  buildings  of  brick  or  terra  cotta,  where 
the  investment  in  buildings  represents  a  large  percentage  of  the 
total  investment. 

Distributing  stations  with  exception  of  delivery  equipment  do 
not  depend  to  such  a  large  extent  on  location,  and  for  that  reason 
are  given  a  longer  life,  although  if  delivery  equipment  is  taken  into 
consideration  the  depreciation  rate  for  the  whole  plant  would  no 
doubt  be  higher  than  for  filling  stations.  Delivery  equipment, 
such  as  tank  wagons,  horses,  trucks,  etc.,  constitute  a  large  per- 
centage of  the  investment  in  distributing  stations  and  are  short 
lived;  therefore,  in  calculating  depreciation  on  distributing  sta- 
tions the  relative  investment  in  warehouse  equipment  and  in 
delivery  equipment  must  be  taken  into  consideration. 

The  rate  of  depreciation  on  tank  cars  is  the  same  as  that  given 
under  refinery  equipment.  The  investment  in  tank  cars  is  really  a 
special  item  when  considering  sales  equipment  as  a  large  number  of 
marketers  do  not  own  any  tank  cars  at  all. 

The  same  thing  applies  to  marine  equipment,  since  only  the 
large  companies  that  do  an  extensive  export  business  possess 
marine  equipment.  It  is  believed  that  an  average  depreciation 
rate  of  10  per  cent  or  a  life  of  10  years  will  cover  this  class  of  equip- 
ment since  equipment  such  as  bulkheads,  docks,  etc.,  have  a  life  of 
only  4  to  6  years,  while  floating  equipment,  such  as  tankers,  will 
easily  last  20  years. 

CLASS  E.— NATURAL  GAS— UTILITY  COMPANIES. 

The  drOling  equipment  and  well  equipment  of  natural  gas  com- 
panies should  be  depreciated  at  the  same  rate  as  drilling  equipment 
and  well  equipment  for  oil  wells,  previously  given. 

The  following  depreciation  rate  is  suggested  for  gas-pipe  lines: 

Per  Cent. 

Mains 8^ 

Gathering  lines 10 

City  lines 10 

Compressor  stations,  including  gas  compressors,  engines,  boilers  and  equip- 
ment, should  be  grouped  into  one  heading  and  depreciated  at  an 

annual  rate  of 14f 

Gathering  stations 16| 

Field  stations 25 

M^ter?  and  regulators 20 


MANUAL   FOR   THE   OIL  AND   GAS    INDUSTRY  77 

The  information  at  hand  in  which  the  cost  of  the  equipment 
was  taken  into  account  showed  that  a  natural  gas  plant  could  be 
depreciated,  as  a  whole,  at  a  rate  of  10  per  cent.  It  is  a  general 
consensus  of  opinion  that  the  average  Ufe  would  not  be  over  10 
years. 

It  is  recommended  that  conditions  existing  on  January  1,  1916, 
be.  used  as  a  basis,  and  that  all  expenses  incurred  to  maintain  the 
output  or  carrying  capacity  of  lines,  as  of  that  date,  be  treated  as 
follows : 

That  intangible  expenses  may  be  charged  direct  to  mainte- 
nance as  an  operating  expense. 

That  tangible  items  be  charged  to  investment  or  capital 
account  and  should  be  given  a  25  per  cent  salvage  value  and  the 
remaining  75  per  cent  charged  off  at  the  rate  of  17^  per  cent  per 
annum  for  aU  gas  properties  other  than  those  in  West  Virginia, 
Pennsylvania,  and  possibly  Ohio,  where  the  natural  gas  plants,  as  a 
whole,  should  be  given  a  15-year  Ufe,  and  the  extensions  figured  on  a 
7-year  life  on  a  15  per  cent  salvage,  and  the  remainder  charged  off 
at  the  rate  of  12  per  cent  per  annum. 

The  above  conclusions  are  based  upon  a  7-year  life  for  gas  fields 
in  West  Virginia,  Pennsylvania,  and  possibly  certain  portions  of 
Ohio,  and  on  a  4-year  life  for  all  other  gas  fields. 

The  shorter  life  for  the  other  gas  fields  can  be  substantiated  by 
numerous  examples,  such  as  Southern  Kansas,  Hogshooter,  Gush- 
ing, and  Pawhuska  fields,  all  of  which  were  large  producers  and 
were  all  practically  exhausted  within  less  than  five  years,  in  which 
the  bulk  was  taken  out  within  the  first  thi-ee  years. 

CLASS  F.— NATURAL  GAS  GASOLINE  PLANTS. 

Compression  plants  may  be  divided  into  compressors,  engines, 
boilers,  auxiliary  equipment,  cooling  equipment,  gathering  and 
distributing  hues,  blending  tanks,  buildings,  and  electrical  equip- 
ment. 

For  absorption  plants,  separate  items  of  absorbers,  stills,  con- 
densors,  cooling  equipment,  auxihary  equipment,  boilers,  engines, 
electrical  equipment,  tanks,  and  loading  racks  may  be  con- 
sidered. 

On  the  whole  the  average  life  of  these  plants  is  not  over  five  or 
six  years. 


78 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY 


The  Fuel  Administration  made  a  survey  of  cost  of  natural  gas 
gasoline  plants.  Over  800  questionnaires  were  sent  out  and  of 
these  about  400  were  considered.  Out  of  175  plants  tabulated 
nearly  all  are  new  plants  or  less  than  two  years  old,  and  of  those 
operating  at  a  loss  almost  all  were  over  four  years  old.  The 
returns  of  some  200  other  plants  were  considered  and  are  older 
plants,  and  were  either  not  operating  or  were  so  defective  in  their 
detail  as  not  to  be  usable  for  comparative  purposes. 

In  consideration  of  these  data  and  other  data  at  hand,  it  is 
recommended  that: 

The  original  cost  be  placed  on  a  20  per  cent  salvage,  and  the 
remaining  80  per  cent  be  depreciated  in  four  years  at  35,  20,  15, 
and  10  per  cent  in  the  respective  years. 


SUMMARY. 


Class. 

No. 

Refer- 
ence. 

Page. 

A 

1 

GS 

2 

G8 

3 

C9 

4 

G9 

5 

70 

6 

70 

7 

70 

8 

70 

9 

71 

10 

71 

Useful 
Life. 


Annual 
Depreciation. 


Drilling  equipment 

Wells 

Dehydrators: 

Electric 

Pipe  and  tanks 

Tanks: 

Steel  5,000-55,000  bbls 

2,500-5,000 

Galvanized  iron  500-2,500. 
Less  than  500 

Wood 

For  movable  tanks: 

Galvanized  iron  500-2,500. 

Less  than  500 

For  water  tanks: 

500-2,500 

Less  than  500 

Tools 

Transportation  equipment. .  .  . 

Water  plants 

Electric  equipment 

Machine  shops 

Buildings: 

Small  wood 

Frame  structure 

Corrugated  iron  siding .  .  .  . 

Concrete 

Brick 

Steel 


Years. 
4 


20 

12 

12 

8 

5 


Per  Cent. 
40-25-15-10 


20 
50 

5 

8J 
8J 

20 

llj 
161 

12J 

20 

331 

33  J 

10 

10 

14? 

10 

61 
16^ 
4 
4 
4 


MANUAL  FOR  THE   OIL  AND   GAS  INDUSTRY 


79 


Summary — Continued. 


Class. 

No. 

Refer- 
ence. 

Useful 
Life. 

Annual 
Depreciation. 

B 

1 
1 

1 

1 
2 
3 

4 
5 
6 

7 

1 

Page. 
71 

72 
73 

75 

76 
77 

Pipe  lines: 

Mains  over  6  inchrs  diameter 

Mains  under  G  inches  diameter 

Years. 

20 
16 
10 

10 
20 

20 
10 

6 

20 
5 

5 

10 
10 

4 
6 

7 
8 

12 
10 
10 

7 

6 

4 

5 
10 

4 
4 

Per  Cent. 

4i 
51 
9 

Less  10  per  cent  salvage. 

10 

c 

5 

Refineries: 

Class  1. — Located  at  point  assuring  a 
long  supply  of  crude  oil: 
or  well-constructed  plants 

Class  2. — Located  at  points  assuring 
supply    of    crude    oil   for 
several  years 

Class  3. — Skimming  plants  and  small 
refineries  of  poor  construc- 
tion, or  located  at  points 
where  supply  of  crude  oil 
is  not  assured  for  a  long 

5 
10 

16! 

D 

Sales  or  marketing  equipment: 

5 

20 

• 

Filling  stations — 

Class  A. — Ordinary  wood  or  cor- 
rugated    steel     con- 
struction  

Class  B. — Brick  and  concrete  or 
e.xtraordinary      con- 
struction  

20 
10 

10 

Tank  wagons — 

25 

161 

14? 
12} 

8} 

E 

Track  and  switches 

Natural  gas  (utility  companies) : 
Drilling  equipment.      (See  A-1.) 
Wells.      (See  A-2.) 
Gas  pipe  lines — 

Gathering  lines 

10 
10 

161 

25 

F 

Meters  and  regulators 

Considered  as  a  whole  plant 

Natural  gas  gasoline: 

Plant — Compression,  with  20  per  cent 

20 
20 

35-20-15-10 

Absorption   plants,   with  20  per  cent 

35-20-15-10 

PART  III. 

ESTIMATION  OF  RECOVERABLE  UNDERGROUND 
RESERVES  OF  OIL. 

PREFACE. 

There  has  been  a  sincere  effort  on  the  part  of  many  petroleum 
engineers  and  technologists  during  the  past  few  years  to  devise  a 
rational  system  for  estimating  underground  reserves  of  oil.  Much 
valuable  work  along  this  line  has  been  done  by  various  engineers 
and  results  have  been  given  out  from  time  to  time  in  the  pubUca- 
tions  of  the  technical  societies  and  Government  bureaus. 

All  sorts  of  methods  and  systems  have  been  devised  and  most  of 
them  have  merit,  but  the  great  difficulty  has  been  to  find  one 
capable  of  general  application. 

Since  the  enactment  of  the  income  and  war  revenue  tax  laws 
producers  have  become  much  interested  in  this  work,  as  they,  as 
well  as  the  technologists  engaged  in  it,  realize  that  the  only  channel 
through  which  might  come  equalization  of  the  tax  burden  on  them 
is  in  the  proper  valuation  (when  permissible)  of  oil  properties, 
careful  estimates  of  the  underground  reserves,  and  then  the  use  ot, 
these  two  factors  in  the  computation  of  proper  depletion  allow- 
ances. 

During  the  autumn  of  the  year  1918,  the  Internal  Revenue 
Bureau  of  the  Treasury  Department,  with  the  active  cooperation 
of  operators  in  the  various  districts,  undertook  the  collection  and 
tabulation  of  production  data  from  all  the  fields  in  the  United  States 
for  the  purpose  of  making  an  intensive  study  of  depletion.  Records 
of  production  of  thousands  of  properties  were  collected  and  tabu- 
lated. These  were  carefully  gone  over  and  studied  by  the  most 
competent  and  experienced  men  in  the  country  and  the  average 
future  production  curves  and  tables  reproduced  on  succeeding 
pages  of  this  manual  are  the  result  of  their  work. 

This  study  has  confirmed  the  belief  heretofore  held  that  it  is 
possible  to  make  estimates  of  recoverable  underground  reserves  of 

80 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY  81 

oil  within  reasonably  narrow  limits.  It  has  shown  that  in  the 
making  of  such  estimates  it  is  simplest  and  safest  to  use  some  vari- 
ation of  production  curve  methods,  because  by  the  use  of  the  pro- 
ductive history  of  a  well  or  property  as  a  basis  for  a  prediction  of  its 
future,  estimation  is  confined  to  the  future  and  the  personal  equa- 
tion thus  reduced  to  a  minimimi. 

Production  curves  and  the  methods  for  using  them  in  making 
estimates  of  underground  reserves  are  very  fully  described  in  sec- 
tion A  following.  It  may  not  be  out  of  place  here,  however,  to 
state  briefly  that  a  production  curve  is  a  graphic  representation  of 
the  decline  in  production  of  a  well  or  group  of  wells,  and  that  the 
problem  presented  to  the  estimator  is  the  extrapolation  or  exten- 
sion of  the  curve  from  the  period  of  last  recorded  production  to  the 
economic  limit  for  the  property. 

A  method  devised  for  use  in  the  older  fields  uses  an  average 
decline  curve  for  this  purpose,  because  a  careful  comparison  of 
production  records  shows  that  while  the  rate  of  decline  in  produc- 
tion varies  widely  over  the  country  as  a  whole,  when  the  production 
records  from  smaller  units  such  as  pools  are  tabulated,  the  decline 
rates  of  individual  wells  or  properties  show  a  striking  similarity, 
although  there  may  be  wide  variations  in  gross  production  figures. 
In  view  of  this  fact,  the  data  collected  are  grouped  according  to 
pools,  and  a  curve  plotted  to  show  the  average  decline  in  pro- 
duction per  well  for  the  pool.  This  curve,  or  such  portion  of  it  as 
is  necessary,  is  reproduced  in  the  extrapolation  of  the  decline  curve 
for  any  particular  property  within  the  district,  but  it  must  be  used 
with  caution  because  this  average  decline  curve  is  only  an  average, 
and  the  probabilities  are  that  each  group  of  wells  within  the  dis- 
trict is  either  above  or  below  the  average.  However,  with  care 
and  the  use  of  judgment,  the  decline  curves  of  any  particular  prop- 
erty may  be  extended  in  this  manner  and  the  results  made  to  show 
very  conservatively  and  within  reasonable  limits  just  what  the 
property  may  be  expected  to  produce  in  the  future. 

To  make  the  average  decline  curve  the  graphs  from  the  pro- 
duction records  for  all  the  tracts  in  the  district  are  assembled  and 
assorted  according  to  the  amount  of  production  in  the  last  year 
shown  and  arranged  in  ascending  order.  The  average  interval 
of  time  required  for  the  decline  between  certain  arbitrarily  fixed 
points,  such  as  from  100  barrels  to  50  barrels,  or  1,000  barrels  to 
500  barrels,  is  found  by  ascertaining  the  numerical  average  of  the 


82  MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY 

time  interval  required  for  such  decline  on  each  of  the  properties  in 
the  district.  The  average  dechnes  so  obtained  are  plotted  and  the 
resultant  curve  represents  a  true  numerical  average  decline  for 
every  well  in  the  district. 

This  curve  is  simply  an  average  of  averages  in  decline  and  deals 
with  known  factors  only. 

Its  greatest  fault  seems  to  lie  in  the  fact  that  in  the  computa- 
tion of  averages,  only  the  records  of  those  wells  which  are  ex- 
hausted, or  very  nearly  so,  can  be  used  in  the  construction  of  the 
lower  end  of  the  curve,  and  usually  the  best  wells  are  at  the  same 
time  producing  at  a  rate  which  may  be  considerably  above  the 
economic  limit  of  the  field.  Consequently,  the  tendency  of  the 
lower  end  of  the  curve  is  to  show  that  the  underground  reserves 
are  somewhat  less  than  they  will  actually  prove  to  be. 

The  advantage  in  the  use  of  this  method  lies  in  the  fact  that  all 
production  records,  no  matter  how  erratic  they  may  be,  are  used  in 
its  construction,  without  any  smoothing  out  processes.  A  further, 
advantage  is  that  the  personal  equation  as  a  factor  in  its  construc- 
tion is  entirely  eliminated. 

This  is  only  one  of  many  methods  devised  for  making  an  aver- 
age decline  curve,  and  in  turn  the  average  decline  curve  is  only  one 
way  of  estimating  reserves  by  production  curve  methods. 

For  the  convenience  of  those  not  accustomed  to  reading  values 
from  curves,  tables  have  been  prepared  showing  the  average  future 
production  which  may  be  expected  from  a  well  in  most  of  the  dis- 
tricts in  the  country  if  the  production  for  the  taxable  year  is  known. 
Curves  and  tables  are  the  same  thing  in  different  form. 

One  thing,  however,  must  be  borne  in  mind.  These  curves  and 
tables  represent  average  conditions  only  in  the  field  or  pool  to  which 
they  apply.  Everyone  knows  that  an  average  well  or  property  is 
seldom  encountered,  so  in  the  application  of  curves  or  tables  to  a 
specific  property  due  allowance  must  be  made. 

A  striking  feature  observed  in  connection  with  the  study  of  these 
curves  is  that  many  decline  curves  of  individual  wells  or  properties 
which  are  anywhere  near  symmetrical,  seem  to  assume  approxi- 
mately the  shape  of  an  hyperbola.  Much  interesting  work  has 
been  done  in  the  investigation  of  this  feature  with  a  view  to  the 
extrapolation  of  decline  curves  mathematically,  because  if  a  true 
decline  curve  is  hyperbolic  in  form,  when  plotted  on  logarithmic 
coordinate  paper  it  becomes  a  straight  line,  with  the  unknown 


MANUAL   FOR   THE  OIL   AND   GAS   INDUSTRY  83 

factor  in  its  equation,  which  is  the  slope  of  the  Hne,  definitely 
fixed  in  the  earlier  periods  of  production.  This  method  of  extra- 
polation of  decline  curves  is  worthy  of  consideration,  but  until 
better  understood  it  must  be  used  with  extreme  caution. 

As  an  essential  element  in  calculating  depletion  allowances  in 
the  estimation  of  underground  reserves,  the  rather  full  discussion 
of  the  methods  found  best  for  making  these  estimates  by  investi- 
gators working  with  the  department  is  given  in  this  manual,  for 
no  single  method  or  formula  which  may  be  generally  applied  has 
been  found. 

The  statement  has  been  made  many  times  in  these  pages,  and 
can  not  be  too  strongly  emphasized,  that  the  curves  and  tables 
presented  herewith  represent  only  average  conditions. 

In  many  cases  they  may  be  used  safely  by  the  operator  of  a 
single  property.  Where,  however,  holdings  in  any  field  or  district 
are  in  any  way  extensive,  it  will,  in  most  cases,  be  necessary  for  the 
operator  to  make  special  estimates,  using  any  or  all  of  the  methods 
discussed  in  this  manual,  or  it  may  even  be  found  necessary  to 
devise  new  combinations  to  fit  the  peculiarities  of  a  particular 
tract. 

In  any  event,  care,  skill,  and  judgment  must  be  exercised  to  the 
utmost,  and  it  is  believed  that  the  effort  expended  in  this  work  on 
the  part  of  the  oil  producer  will  be  repaid  many  fold.  Not  only 
from  a  tax  standpoint  will  this  benefit  come.  A  full  knowledge  of 
conditions  such  as  will  be  brought  out  by  a  study  of  this  problem 
will  put  the  oil-producing  business  generally  on  the  much  firmer 
and  safer  foundation  to  wliich  it  is  rightfully  entitled. 

Section  A. 

METHODS  OF  ESTIMATING  RECOVERABLE  OIL  RESERVES. 

Estimation  of  recoverable  oil  is  possible. — The  estimation  of 
the  future  production  of  oil  wells  or  of  the  recoverable  oil  underlying 
a  property  in  the  past  has  been  considered  an  almost  unsolvable 
problem,  but  scientific  })rogress  has  disclosed  reasonably  accurate 
solutions,  especially  where  sufficient  dependal)le  data  are  brought 
together  and  arranged  in  an  orderly  manner,  for  then  it  becomes 
evident  that  there  is  "  a  system  to  things  "  and  that  "  freaks  "  are 
comparatively  few.     The  recovery  of  oil  is  controlled  by  scientific 


84 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 


laws,  and  where  enough  facts  are  known  these  laws  make  them- 
selves manifest. 

During  the  past  ten  years  many  petroleum  engineers  have  been 
working  on  the  problem  of  estimating  the  future  production  of  oil 
wells,  and  much  progress  has  been  made.  In  fact,  when  enough 
facts  are  available,  surprisingly  close  estimates  are  usually  possible, 
and  in  the  future,  as  more  and  more  data  are  compiled  and  ana- 
lyzed, it  will  be  possible  to  make  much  closer  estimates. 

Plotting  production  curves. — The  production-curve  method  is 
one  of  the  simplest  and,  when  sufficient  data  are  available,  is,  per- 
haps, the  most  accurate  of  all  the  methods  for  estimating  the  future 
production  of  oil  wells.  A  production  curve  is  a  graphical  record 
of  the  production  of  a  well  or  group  of  wells,  plotted  on  coordinate 
paper  (Fig.  1).  It  is  desirable  to  have  the  production  records  of 
individual  wells,  but  as  these  are  kept  in  but  a  few  fields,  it  is 
usually  necessary  to  use  the  production  record  of  the  group  of 
wells  on  a  property. 

To  provide  a  basis  of  comparison  between  wells,  the  yearly  pro- 
duction of  a  property  is  divided  by  the  number  of  wells  producing 
each  year,  thus  giving  the  average  production  per  well  for  each 
year.  The  record  of  an  Oklahoma  property  that  has  been  pre- 
pared for  plotting  in  a  production  curve  is  given  herewith. 


Year. 

Produc- 
tion. 

Wells 
Producing. 

Average 
per  Well. 

Year. 

Produc- 
tion. 

Wells 
Producing. 

.\verage 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

1906 

46,860 

5 

9,372 

1912 

2,462 

G 

410 

1907 

31,717 

6 

5,286 

1913 

1,641 

6 

274 

1908 

15,003 

6 

2,501 

1914 

1,061 

6 

177 

1909 

11,031 

6 

1,838 

1915 

578 

6 

96 

1910 

7,047 

6 

1,174 

1916 

218 

6 

36 

1911 

4,522 

6 

754 

On  a  sheet  of  coordinate  paper,  as  in  Fig.  1,  the  spaces  between 
the  light  horizontal  lines  represent  100  barrels  each  and  those  be- 
tween the  heavy  lines  which  are  ten  times  as  far  apart,  represent 
1,000  barrels  each.  The  heavy  vertical  lines  represent  years; 
thus,  space  between  the  horizontal  lines  represents  production 
and  between  the  vertical  lines  time.  For  convenience,  these  lines 
are  labeled  on  the  margins  as  in  Figs.  1  and  2. 

Taking  the  record  given,  the  first  year  is  1906,  during  which 


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111069--19.  '"^-   '-PRODUCTION    DECLINE  CURVE  FOR  A   PROPERTY   IN  OKLAHOMA.  ^^^  ,„^^  p^^^  ^^ 


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FIG.  2.— PRODUCTION   DECLINE  CURVE,  SHOWING  THE  EXTENDED  CURVE  OF  PROBABLE  FUTURE  PRODUCTION. 


/S24       /S25 


(To  face  page  85.) 


MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY  85 

year  the  average  production  for  each  well  was  9,372  barrels,  A 
point  is  then  made  on  the  vertical  line  representing  the  year  1906 
and  a  distance  representing  9,372  barrels  above  the  bottom,  which 
is  9  heavy  lines  and  3|  light  hnes.  Similarly  a  point  is  made  on 
the  line  representing  1907,  5  heavy  lines  and  3  light  lines  above  the 
bottom.  And  on  the  line  representing  1908,  2  hea\'y  and  5  light 
lines  above  the  bottom  show  the  production  of  2,501  barrels  for 
that  year.  The  production  for  the  rest  of  the  years  are  then  plotted 
and  th"^  points  connected  up  by  lines  to  make  the  curve  as  in  Fig.  1. 
It  will  be  observed  at  once  that  the  plotted  record  makes  a  fairly 
regular  and  symmetrical  curve. 

Manifestly,  there  is  a  certain  relation  between  the  production 
of  the  successive  years  that  is  not  easily  seen  in  the  column  of  fig- 
ures from  which  this  curve  was  derived.  Plotting  production 
records  in  this  manner  has  many  advantages  and  permits  the 
mind  to  grasp  readily  facts  that  otherwise  would  be  obscured  in  a 
mass  of  figures. 

Estimating  future  production  by  production  curves. — Many 
tJiousand  production  or  decline  curves  have  been  plotted  by 
petroleum  engineers  in  the  manner  shown,  and  from  this  wide 
experience  it  has  developed  that  the  relationships  between  the 
production  of  various  years  are  such  that  the  curves  are  usually 
notably  symmetrical.  Furthermore,  it  has  been  found  that  such 
curves  can  be  extended  beyond  the  actual  period  of  production  by 
continuing  the  curves  in  accordance  with  their  symmetry  and 
that  such  projections,  if  skillfully  made,  provide  fairly  trust- 
worthy estimates  of  the  future  production  of  the  well. 

The  estimation  of  the  future  production  by  the  curves  of  past 
production  is  illustrated  in  Fig.  2.  The  actual  record  extends  six 
years — from  1911  to  191G — and  is  shown  by  the  small  circles  con- 
nected by  the  heavy  lines.  The  dotted  line  shows  the  symmetry  of 
this  portion  of  the  curve  and  beyond  the  year  1916,  shows  the 
extension  from  which  estimates  of  future  productions  are  made  up 
to  the  year  1925.  For  1917  the  estimated  production  is  1,700 
barrels,  for  1918,  1,500  barrels,  and  for  1919,  1,300  barrels.  By 
adding  these  estimates  of  the  future  years,  an  estimate  of  the  total 
future  production  is  obtained. 

It  is  to  be  noted  that  production  curves  like  Figs.  1  and  2  deal 
with  actual  facts  and  conditions  on  particular  properties.  Only 
the  oil  gauged  is  considered,  hence  all  the  various  practical  facts 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY  85 

year  the  average  production  for  each  well  was  9,372  barrels.  A 
point  is  then  made  on  the  vertical  line  representing  the  year  1906 
and  a  distance  representing  9,372  barrels  above  the  bottom,  which 
is  9  heavy  lines  and  3f  light  lines.  Similarly  a  point  is  made  on 
the  line  representing  1907,  5  heavy  lines  and  3  light  lines  above  the 
bottom.  And  on  the  line  representing  1908,  2  heavy  and  5  light 
hnes  above  the  bottom  show  the  production  of  2,501  barrels  for 
that  year.  The  production  for  the  rest  of  the  years  are  then  plotted 
and  th-^  points  connected  up  by  lines  to  make  the  curve  as  in  Fig.  1, 
It  will  be  observed  at  once  that  the  plotted  record  makes  a  fairly 
regular  and  symmetrical  curve. 

Manifestly,  there  is  a  certain  relation  between  the  production 
of  the  successive  years  that  is  not  easily  seen  in  the  column  of  fig- 
ures from  which  this  curve  was  derived.  Plotting  production 
records  in  this  manner  has  many  advantages  and  permits  the 
mind  to  grasp  readily  facts  that  otherwise  would  be  obscured  in  a 
mass  of  figures. 

Estimating  future  production  by  production  curves. — Many 
thousand  production  or  decline  curves  have  been  plotted  by 
petroleum  engineers  in  the  manner  shown,  and  from  this  wide 
experience  it  has  developed  that  the  relationships  between  the 
production  of  various  years  are  such  that  the  curves  are  usually 
notably  symmetrical.  Furthermore,  it  has  been  found  that  such 
curves  can  be  extended  beyond  the  actual  period  of  production  by 
continuing  the  curves  in  accordance  with  their  symmetry  and 
that  such  projections,  if  sldllfully  made,  provide  fairly  trust- 
worthy estimates  of  the  future  production  of  the  well. 

The  estimation  of  the  future  production  by  the  curves  of  past 
production  is  illustrated  in  Fig.  2.  The  actual  record  extends  six 
years — from  1911  to  1916 — and  is  shown  by  the  small  circles  con- 
nected by  the  heavy  lines.  The  dotted  line  shows  the  symmetry  of 
this  portion  of  the  curve  and  beyond  the  year  1916,  shows  the 
extension  from  which  estimates  of  future  productions  are  made  up 
to  the  year  1925.  For  1917  the  estimated  production  is  1,700 
barrels,  for  1918,  1,500  barrels,  and  for  1919,  1,300  barrels.  By 
adding  these  estimates  of  the  future  years,  an  estiniate  of  the  total 
future  production  is  obtained. 

It  is  to  be  noted  that  production  curves  like  Figs.  1  and  2  deal 
with  actual  facts  and  conditions  on  particular  properties.  Only 
the  oil  gauged  is  considered,  hence  all  the  various  practical  facts 


86  MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY 

of  field  conditions  are  automatically  taken  into  account.  The 
extension  of  the  curve  estimating  future  production  is  based  on  the 
past  behavior  of  the  wells  on  the  particular  property  which  estab- 
lished the  symmetry  of  the  curve.  This  symmetry  is  not  acci- 
dental but  is  the  result  of  underlying  natural  laws  governing  the 
expulsion  of  the  oil  from  the  producing  strata.  In  Fig.  1  it  is 
evident  that  the  production  of  the  last  six  years  could  have  been 
closely  estimated  from  the  production  curve  of  the  first  five  years. 
This  method  and  others  based  on  it  have  proved  satisfactory  in  the 
appraisal  of  many  large  properties. 

Obviously,  manner  of  operation,  accidents,  and  other  factors 
will  influence  the  future  production  just  as  they  have  the  past 
production,  but  experience  has  shown  that  ordinarily  these  are  not 
likely  to  cause  wide  deviation  from  estimates  that  have  been  care- 
fully made.  Examination  of  the  individual  production  records 
will  show  whether  the  probability  of  such  occurrences  will  make 
estimates  unsafe. 

The  Appraisal-curve  method. — The  production-curve  method, 
just  discussed,  necessitates  a  record  of  at  least  four  years  before 
any  reliable  estimate  of  the  future  production  is  possible,  and 
usually  such  estimates  can  not  be  made  satisfactorily  until  the 
wells  have  produced  for  several  years.  In  the  most  satisfactory 
methods  for  properties  that  have  not  produced  this  long,  the  future 
production  of  wells  is  estimated  by  comparison  with  the  behavior 
of  other  wells  in  the  same  or  similar  districts  that  have  produced 
long  enough  to  establish  trustworthy  production  curves.  Usually 
the  methods  of  estimation  are  based  on  the  average  behavior  of 
the  older  wells  because  the  behavior  of  the  new  wells  will  approxi- 
mate this  average. 

The  appraisal  curve  is  built  up  from  records  of  individual  wells 
or  groups  of  wells  within  a  certain  district  and  is  applied  to  wells 
within  the  same  district  that  have  not  produced  long  enough  to  per- 
mit estimates  of  future  production  by  extension  of  the  production 
curve.  It  may  be  necessary  at  times  to  apply  appraisal  curves  of 
one  district  to  other  districts  for  which  there  are  not  enough  reliable 
records  to  make  appraisal  curves,  and  in  such  cases  care  must  be 
taken  to  select  curves  from  districts  most  similar. 

The  appraisal  curve,  illustrated  by  Fig.  3,  is  based  on  the 
relation  that  exists  between  the  production  of  wells  for  their  first 
year,  and  the  quantities  of  oil  they  will  produce  ultimately.     This 


MANUAL   FOR  THE   OIL   AND   GAS   INDUSTRY  87 

particular  figure  was  drawn  from  the  production  records  of  209 
properties  in  an  Oklahoma  field.  As  the  average  property  in  that 
field  contains  10  producing  wells,  the  figure  may  be  said  to  repre- 
sent about  2,000  wells.  The  records  of  each  property  were  taken 
and  each  year's  average  daily  production  per  well  was  computed 
and  curves  plotted  from  them.  Only  records  where  practically 
the  full  production  had  been  obtained  or  where  the  future  could 
be  estimated  with  confidence  were  used.  From  these  curves  the 
future  production  of  each  property  was  estimated  as  explained 
above  (Figs.  1  and  2).  The  future  production  of  each  property 
was  added  to  past  production  to  determine  the  ultimate  produc- 
tion for  each  property.  The  next  step  was  to  plot  for  each  property 
the  average  production  per  well  during  the  first  j^ear  or  second  year 
against  the  ultimate  production  of  the  well.  Each  dot,  therefore, 
on  Fig.  3,  shows  the  average  production  per  well  the  first  year  on  a 
property  and  the  estimated  average  ultimate  production  per  well. 

These  dots,  which  represent  the  ultimate  production  of  more 
than  200  properties,  on  which  the  wells  were  of  niany  different 
sizes  the  first  j^ear,  arrange  themselves  in  a  strikingly  orderly 
manner,  leaving  no  doubt  of  the  existence  of  a  definite  relation 
between  the  first  year's  production  of  a  well  and  its  ultimate  pro- 
duction. There  is  a  considerable  variation  in  ultimate  produc- 
tion, however,  both  for  wells  of  different  and  for  wells  of  the  same 
initial  output. 

These  dots  define  the  positions  of  the  three  curves  drawn  in  to 
show  the  average  and  the  range  in  ultimate  production  that  may 
be  expected  from  wells  of  different  output  in  this  field.  It  shows 
that  two  wells  in  this  field  with  the  same  production  the  first  year 
may  produce  different  totals,  yet  the  amount  that  a  well  of  a  cer- 
tain output  will  produce  will  not  exceed  a  certain  maximum,  nor 
will  it  be  less  than  a  certain  minimum.  The  producer,  therefore, 
can  be  reasonably  sure  that  he  will  not  get  more  than  a  certain 
maximum  amount  of  oil  nor  less  than  a  certain  minimum  amount 
and  is  really  more  likely  to  obtain  finally  the  amount  shown  by  the 
average  curve  than  either  the  maximum  or  mininuun. 

Fig.  3  has  been  worked  out  on  the  law  of  averages  similar  to 
the  fundamental  laws  underlying  life  insurance.  Actuaries  know, 
not  by  theory  but  from  the  analysis  of  great  masses  of  data,  the 
probable  life  of  a  man  of  any  specified  age,  though  an  individual 
man  might  die  the  next  day,  or,  on  the  other  hand,  might  live  to  be 


88  MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY 

of  a  very  old  age.  If  10,000  men  are  considered,  however,  it  is 
possible  to  predict  within  extremely  narrow  limits  the  age  at 
which  the  average  man  of  the  group  will  die,  and  also  how  many 
men  of  the  10,000  will  die  at  any  specified  age. 

The  method  illustrated  in  Fig.  3  makes  use  of  the  first  year's 
production,  but  the  most  recent  year's  production  may  be  used  with 
equal  assurance,  and  the  total  production,  beginning  with  the 
production  of  the  well  for  the  past  year,  can  be  worked  out  in  the 
same  manner.  This  fact  is  based  on  a  conclusion  for  which  there 
seems  to  be  abundant  statistical  proof.     This  is  as  follows : 

If  two  wells  under  similar  conditions  produce  equal  amounts  dur- 
ing any  given  year  the  amounts  they  will  produce  thereafter,  on  the 
average,  will  be  approximately  equal,  regardless  of  their  relative  ages. 
That  is,  if  two  groups  of  wells  in  the  same  pool  have  averaged, 
say,  5  barrels  per  day  during  the  past  year,  they  will  on  the  average 
produce  the  same  amount  of  oil  in  the  future,  even  though  the  wells 
of  one  group  may  be  only  2  years  old,  whereas  the  wells  of  the  other 
group  may  be  5  years  old.  The  writers  were  at  first  skeptical,  but 
finally  were  forced  to  this  conclusion  because  of  the  preponderance 
of  evidence  disclosed  by  the  records  of  many  thousands  of  wells  in 
many  different  fields. 

It  must  be  carefully  noted  that  the  above  statement  is  made  for 
the  average  and  applies  to  only  one  pool.  The  future  production  of 
any  two  wells  may  differ  widely  but  for  two  large  groups  of  wells  in 
the  same  district  whose  current  production  averages  the  same,  the 
statement  holds  true,  hence  if  nothing  is  known  of  the  past  his- 
tories of  two  wells  from  which  their  futures  may  be  estimated,  their 
chances  of  production  will  be  equal  even  though  one  well  is  much 
older  and  according  to  the  popular  idea  has  a  more  settled  produc- 
tion. 

This  law  of  equal  expectations  makes  possible  the  derivation  of 
appraisal  curves  like  Fig.  3  by  other  methods  than  the  one  illus- 
trated. The  curves  for  many  of  the  fields  were  checked  by  two  or 
more  methods  of  derivation. 

To  estimate  future  production  from  this  curve  it  is  necessary 
to  know  the  first  or  the  most  recent  year's  production  and  the 
number  of  wells  producing  during  that  year.  From  this  the  aver- 
age production  per  well  is  computed.  Readings  are  then  made  at 
the  intersections  of  the  vertical  lines,  representing  the  average 
yearly  production  per  well  with  the  curves,  and  the  horizontal  lines 


2000 

Prodi 

■IG.  3.— / 


300O  /2000  /6000         £0000         ^4000  B&(^00  JZOOO  JCOOO        -40000         ^ooo 

-  Production      Per  iVe//     P/r^t    >^^/~— 


111009"— 19. 


FIG.   3.— APPRAISAL   CURVE   FOR   ; 


HOMA   OIL   FIELD. 


■^ooo        -jsaoo 


(To  face  page  88.) 


MANUAL  FOR  THE   OIL  AND   GAS  INDUSTRY  89 

on  which  these  intersections  lie  are  then  followed  to  the  right  or  left. 
This  gives  the  maximum,  average,  and  minimum  ultimate  pro- 
duction that  may  be  expected  per  well.  For  example,  if  the  wells 
average  30  barrels  daily  during  any  year,  the  30-barrel  line  is  fol- 
lowed vertically  to  the  intersection  with  the  jninimum  curve  at 
16,200,  the  average  at  28,000,  and  the  maximum  at  40,500  barrels. 
Thus,  the  average  30-barrel  well  will  produce  not  more  than  40,500 
barrels,  at  least  16,200  barrels,  but  more  likely  it  will  produce 
approximately  28,000  barrels.  To  compute  the  future  produc- 
tion, the  year's  production — 10,950  barrels — must  be  subtracted 
from  these  estimates.  This  gives  the  maximum,  average,  and 
minimum  future  estimates  as  29,550,  17,050,  and  5,250  barrels, 
respectively. 

In  some  cases  the  average  future  production  curves  shown  in  the 
succeeding  pages  were  determined  in  this  way — that  is,  the  past 
year's  production  was  subtracted  from  the  estimated  average 
ultimate  production,  as  shown  by  the  average  ultimate  produc- 
tion curves.  These  estimates  of  average  future  production  were 
plotted  and  a  curve  drawn  through  the  plotted  points.  In  other 
cases  the  future-production  curves  were  derived  directly  from  the 
average-production  curve.  By  multiplying  these  estimates  of 
future  production  by  the  number  of  producing  wells,  the  estimated 
future  recovery  for  the  developed  portion  of  the  property  may  be 
ascertained.  It  should  be  remembered,  in  using  these  future- 
production  curves,  that  they  represent  the  average  and  were 
based  on  all  the  evidence  available.  They  do  not  take  into  con- 
sideration the  increase  in  oil  production  due  to  the  use  of  stim- 
ulative processes,  such  as  compressed  air,  reshooting,  flooding, 
etc. 

In  the  appraisal  curve  (Fig.  3)  it  is  to  be  noted  that  though  the 
limits  of  variation  are  set  for  a  well  of  a  particular  size,  these  limits 
permit  a  considerable  variation.  If  nothing  is  known  beyond  the 
first  year's  production,  it  will  be  necessary  to  assume  that  the  well 
is  an  average  well  and  the  average  curve  should  be  used.  The 
probabilities  are  that  the  well  will  actually  be  nearer  the  average 
than  either  extreme,  as  shown  by  the  dots  on  Fig.  3.  If,  however, 
the  record  extends  back  two  or  more  years  it  becomes  possible  to 
tell  whether  the  well  is  an  average  well  or  if  it  deviates  from  the 
average  the  direction  and  degree  of  such  deviation.  In  other 
words,  the  longer  the  past  history  of  tlu>  well,  the  more  nearly 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY  89 

on  which  these  intersections  lie  are  then  followed  to  the  right  or  left. 
This  gives  the  maximum,  average,  and  minimum  ultimate  pro- 
duction that  may  be  expected  per  well.  For  example,  if  the  wells 
average  30  barrels  daily  during  any  year,  the  30-barrel  line  is  fol- 
lowed vertically  to  the  intersection  with  the  minimum  curve  at 
16,200,  the  average  at  28,000,  and  the  maxhnum  at  40,500  barrels. 
Thus,  the  average  30-barrel  well  will  produce  not  niore  than  40,500 
barrels,  at  least  16,200  barrels,  but  more  likely  it  will  produce 
approximately  28,000  barrels.  To  compute  the  future  produc- 
tion, the  year's  production — 10,950  barrels — must  be  subtracted 
from  these  estimates.  This  gives  the  maximum,  average,  and 
minimum  future  estimates  as  29,550,  17,050,  and  5,250  barrels, 
respectively. 

In  some  cases  the  average  future  production  curves  shown  in  the 
succeeding  pages  were  determined  in  this  way — that  is,  the  past 
year's  production  was  subtracted  from  the  estimated  average 
ultimate  production,  as  shown  by  the  average  ultimate  produc- 
tion curves.  These  estimates  of  average  future  production  were 
plotted  and  a  curve  drawn  through  the  plotted  points.  In  other 
cases  the  future-production  curves  were  derived  directly  from  the 
average-production  curve.  By  nmltiplying  these  estimates  of 
future  production  by  the  number  of  producing  wells,  the  estimated 
future  recovery  for  the  developed  portion  of  the  property  may  be 
ascertained.  It  should  be  remembered,  in  using  these  future- 
production  curves,  that  they  represent  the  average  and  were 
based  on  all  the  evidence  available.  They  do  not  take  into  con- 
sideration the  increase  in  oil  production  due  to  the  use  of  stim- 
ulative processes,  such  as  compressed  air,  reshooting,  flooding, 
etc. 

In  the  appraisal  curve  (Fig.  3)  it  is  to  be  noted  that  though  the 
limits  of  variation  are  set  for  a  well  of  a  particular  size,  these  limits 
permit  a  considerable  variation.  If  nothing  is  known  beyond  the 
first  year's  production,  it  will  be  necessary  to  assume  that  the  well 
is  an  average  well  and  the  average  curve  should  be  used.  The 
probabilities  are  that  the  well  will  actually  be  nearer  the  average 
than  cither  extreme,  as  shown  by  the  dots  on  Fig.  3.  If,  however, 
the  record  extends  back  two  or  more  years  it  becomes  possible  to 
tell  whether  the  well  is  an  average  well  or  if  it  deviates  from  the 
average  the  direction  and  degree  of  such  deviation.  In  other 
words,  the  longer  the  past  history  of  the  well,  the  niore  nearly 


90  MANUAL   FOR  THE   OIL   AND   GAS   INDUSTRY 

it  can  be  classified  according  to  its  probable  future  behavior.  If 
the  record  is  long  enough,  a  production  curve  like  that  shown  in 
Fig.  2  may  be  used  which  will  in  such  case  be  preferable  to  these 
general  curves.  In  estimating  the  future  production,  the  estimates 
should  be  revised  at  the  end  of  each  year  instead  of  carrying  for- 
ward errors  from  year  to  year.  In  this  way  poor  estimates  caused 
by  lack  of  data  or  changed  conditions  on  the  property  are  not  per- 
petuated. To  show  how  these  readjustments  are  made,  the  fol- 
lowing example  is  given: 

A  property  gave  an  average  production  of  12,410  barrels,  or  34 
barrels  per  well  per  day,  during  the  first  year.  An  average  34- 
barrel  well  in  this  field  would  produce  a  total  of  30,500  barrels 
ultimately,  of  which  12,410  barrels  (34X365)  were  produced  during 
the  first  year.  This  leaves  a  future  production  of  18,090  barrels 
per  well.  In  order  to  determine  the  average  daily  production  for 
such  a  well  during  the  second  year,  we  must  assume  the  figure  of 
18,000  barrels  as  its  ultimate  production.  Applying  the  afore- 
said curve  (Fig.  3),  we  follow  the  horizontal  line  representing  this 
ultimate  production  across  the  chart  to  its  intersection  with  the 
"  average  "  curve.  This  gives  5,840  barrels,  or  16  barrels  as  the 
first  year's  average  daily  production  as  a  well  with  this  ultimate 
production.  Applying  the  law  stated  on  page  88,  it  becomes  evi- 
dent that  the  above  figure  of  16  barrels  is  approximatel}^  equal  to 
the  daily  production  for  its  second  year  of  a  well  which  produced 
34  barrels  daily  during  its  first  year.  Multiplying  16  by  365  gives 
a  total  of  about  5,840  barrels,  which  represents  the  amount  pro- 
duced during  the  second  year.  The  sum  of  the  first  and  second 
year's  production  of  this  well  is  about  18,070.  This  amount 
deducted  from  the  original  ultimate  production  of  30,500  barrels 
leaves  a  future  production  of  about  12,430  barrels.  By  repeat- 
ing the  same  process  for  each  successive  future  year  until  the  esti- 
mated ultimate  production  is  extinguished,  the  total  decline  of  this 
well  will  be  obtained. 

Suppose  the  well  actually  produced  20  barrels  per  day,  how- 
ever, instead  of  16  barrels,  or  7,300  barrels  for  the  year  instead  of 
5,640.  This  means  that  the  well  is  above  the  average  by  30  per 
cent,  and  proper  corrections  are  therefore  made.  B}^  this  means 
estimates  may  be  corrected  yearly  and  the  depletion  charges  made 
more  and  more  accurate  as  time  goes  on. 

Unusual  cases  will  have  to  be    dealt  with   separately.     For 


MANUAL   FOR  THE  OIL   AND   GAS   INDUSTRY  91 

instance,  it  may  not  be  possible  to  niake  trustworthy  estimates  of 
the  future  production  of  some  wells  by  this  method,  because  of  the 
irregularity  of  their  production.  Also,  those  wells  wherein  stimu- 
lative process3s  are  used  will  have  to  be  considered  separately. 
Wherever  the  wells  on  a  property  produce  regularly,  however,  and 
where  the  property  is  fairly  well  drilled  up,  and  the  proved  acreage 
can  be  easily  determined,  the  above  method  should  be  of  great 
value  to  the  oil  producers  in  making  estimates  of  future  pro- 
duction 

The  same  general  procedure  may  be  applied  in  making  esti- 
mates of  the  ultimate  production  of  undrilled  but  proven  oil  land. 
Proven  oil  land  is  that  which  has  been  shoivn  by  finished  wells,  sup- 
plemented by  geologic  data,  to  be  such  that  other  wells  drilled  thereon 
are  practically  certain  to  be  commercial  producers.  The  average 
future  production  curve  may  be  used  in  making  estimates  of  the 
future  production  of  a  practically  drilled  up  near-by  similar  tract 
and  the  ultimate  production  per  acre  estimated.  These  values, 
with  necessary  modifications,  on  account  of  position  on  structure, 
sand  characteristics,  drainage,  etc.,  may  be  applied  to  the  undrilled 
tract 

Another  method  is  to  estimate  the  first  year's  production  of 
wells  to  be  drilled  on  the  proved  land  and  determine  their  future 
by  use  of  the  average  future  production  curve.  The  ultimate 
production  of  the  tract  is  the  sum  of  the  future  production  and  of 
the  first  year's  production. 

Any  estimates  of  the  amount  of  oil  that  will  be  recovered  from 
an  undrilled  but  proven  tract  are  subject  to  great  inaccuracies. 
They  are  estimates  in  the  truest  sense  of  the  word,  but  it  is  believed 
that  this  method  is  as  satisfactory  as  any  other  for  obtaining  the 
probable  productivity  of  a  tract. 

No  attempt  has  been  made  to  cover  all  the  ramifications  of  the 
problems  of  estimating  the  future  production  of  wells  or  of  the 
underground  reserves  of  undrilled  area.  The  purpose  of  this 
article  has  been,  first,  to  point  out  that  if  sufficient  data  are  col- 
lected and  analyzed,  the  law  of  averages  discloses  systematic 
relations  between  the  past  and  future  production,  and,  second,  to 
show  one  convenient  method  that  may  l)e  used  to  estimate  reserves 
as  a  basis  for  calculating  depletion  deductions  in  a  sicentific  manner. 


92  MANUAL   FOR  THE  OIL  AND   GAS   INDUSTRY 

SECTION  B. 

AVERAGE  FUTURE  PRODUCTION  CURVES  AND  TABLES. 

FUTURE  PRODUCTION  CURVES  FOR  THE  APPALACHIAN 
DISTRICT. 

The  Appalachian  oil  and  gas  district  occupies  an  elongated 
elliptical-shaped  area  extending  northeast  and  southwest  across 
the  Appalachian  Plateaus  from  southwestern  New  York  to  Ten- 
nessee, a  distance  of  about  500  miles.  In  its  broadest  part,  cen- 
tering in  eastern  Ohio,  the  district  is  about  150  miles  wide.  Thence 
northward  and  southward  the  productive  zone  rapidly  diminishes 
in  width,  and  its  extension  across  Kentucky  is  by  small,  widely 
separated  pools.  The  area  of  greatest  oil  development  occupies  a 
narrower  zone  which  averages  less  than  50  miles  in  width  and 
centers  in  the  panhandle  of  West  Virginia. 

The  oil  and  gas  bearing  sands  occur  throughout  a  long  strati- 
graphic  interval,  including  rocks  ranging  in  age  from  Ordovician  to 
Carboniferous.  The  strata  consist  of  preponderating  shale,  lenses 
of  sandstone — which  are  the  main  oil  and  gas  horizons — and  subor- 
dinate limestone.  The  sandstones  merge  into  shales  toward  the 
west,  where  there  is  also  a  greater  proportion  of  limestone  in  the 
section.  There  is  a  marked  decrease  in  thickness  of  the  strata 
toward  the  west,  notably  of  the  Upper  Devonian.  This  is  shown 
by  the  increase  in  the  interval  between  the  Berea  sandstone  and 
the  Corniferous  limestone,  from  500  feet  in  central  Ohio  to  more 
than  5,800  feet  in  northern  West  Virginia.  And  southward  across 
West  Virginia  there  is  a  notable  thickening  of  the  Pottsville  forma- 
tion. For  this  reason  and  because  of  the  basin  structure  of  the 
district  the  "  Clinton  "  sandstone  which  occurs  between  two  and 
three  thousand  feet  beneath  the  surface  in  central  Ohio  is  more 
than  7,000  feet  deep  in  western  Pennsylvania  and  northern  West 
Virginia  where  it  was  not  encountered  in  two  recently  sunk  very 
deep  test  holes. 

The  Appalachian  oil  and  gas  district  lies  in  the  geosyncline  that 
extends  between  the  Cincinnati  anticline  on  the  west  and  the  zone 
of  steeply  folded  rocks  of  the  Allegheny  Mountains  on  the  east. 
The  syncline  is  a  spoonshaped  trough  in  which  the  rocks  rise  north- 
westward, northward,  and  southeastward  froni  the  lowest  part  of 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY  93 

the  basin  situated  in  West  Virginia  near  the  southwestern  corner 
of  Pennsylvania.  Superimposed  on  this  larger  structure  are  a 
series  of  folds  by  which  the  rocks  are  warped  into  irregular  and 
generally  nonpersistent  anticlines  and  synclines,  the  axes  of  which 
undulate  and  overlap.  The  axial  trend  throughout  the  greater 
part  of  the  district  is  northeast-southwest,  but  in  southern  West 
Virginia  and  Kentucky  the  trend  becomes  more  westward.  The 
folds  decrease  in  intensity  westward  from  the  eastern  margin  of 
the  district  and  west  of  the  axis  of  the  geosyncline  the  folding  is  so 
gentle  that  the  rocks  are  warped  into  irregular  wrinkles  without 
marked  axial  trend.  Along  the  western  margin  of  the  district  the 
folds  practically  disappear  and  give  way  to  a  monocline  on  which 
the  rocks  rise  westward  at  the  rate  of  about  60  feet  per  mile. 

Considered  as  a  whole,  the  most  productive  oil  belt  occurs  con- 
tiguous to  the  central  axis  of  the  geosyncline  and  the  largest  accu- 
mulations of  gas  are  found  along  the  outer  margins  of  the  trough. 
But  pools  of  oil  and  gas  of  varying  size  separated  by  nonproductive 
areas  are  irregularly  distributed  throughout  the  district.  The 
pools  are  characteristically  elongated  in  outline  and  their  longer 
dimensions  are  prevailingly  parallel  to  the  structural  trend.  The 
location  of  most  of  the  gas  pools  has  been  distinctly  determined 
by  structure.  They  occur  along  the  crests  of  anticlines  or  along 
the  updip  termination  of  lenses  of  sandstone  where  they  merge 
with  shale,  or  where  there  is  a  marked  decrease  in  porosity  of  the 
pay  sand.  The  influence  of  structure  on  oil  accumulation  is  also 
pronounced.  In  the  absence  of  gas  some  oil  pools  occur  on  the 
crests  of  antichnes.  Where  much  gas  is  present  pools  occur  on 
the  flanks  of  anticlines  below  the  gas  and  above  the  edge  water; 
others  occur  on  terraces  marked  by  changes  in  the  rate  of  dip. 
In  the  absence  of  water  in  the  rocks,  petroleum  tends  to  occur  in 
the  synclines.  But  in  many  pools  the  effect  of  structure  is  not  so 
evident  and  lithology  has  been  the  controlling  factor.  The  loca- 
tion of  many  of  the  oil  pools  in  the  Appalachian  region  is  prin- 
cipally due  to  the  position  and  porosity  of  the  lenticular  reservoir 
rocks.  These  factors  account  for  the  irregular  shape  of  many  of 
the  pools  and  for  their  not  uncommon  occurrence  "  off  structure." 

The  petroleum  from  the  Appalachian  region  is  a  high-grade 
paraffin  oil.  The  product  of  New  York,  Ohio,  Pennsylvania,  and 
West  Virginia  has  an  average  specific  gravity  not  far  from  0.800 
(45°  Baume) .     The  average  for  Kentucky  is  not  quite  so  high. 


94  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

The  total  production  of  petroleum  in  New  York,  Pennsylvania, 
West  Virginia,  Kentucky,  and  Tennessee  down  to  January  1,  1917, 
was  1,060,338,464  barrels.  Complete  data  for  the  Appalachian 
region  as  a  whole  are  not  available  because  separate  figures  have 
not  been  kept  for  eastern  Ohio  district  from  the  western  part  of 
the  State,  which  is  included  in  the  Lima-Indiana  district. 

The  maximum  annual  output  for  New  York  and  Pennsylvania 
was  obtained  in  1891,  when  more  than  33,000,000  barrels  were  pro- 
duced. Since  1900  there  has  been  a  fairly  uniform  decrease  in 
production  down  to  1912,  when  the  lowest  annual  production, 
8,712,076  barrels,  was  recorded  for  New  York  and  Pennsylvania. 
In  1913  and  1914  there  were  slight  increases  and  for  the  last  five 
years  the  variation  in  production  from  year  to  year  has  been 
abnormally  small.  This  change  in  rate  makes  the  extension  of 
the  curve,  in  an  endeavor  to  estimate  future  yield,  somewhat 
doubtful.  Nevertheless,  because  the  peak  production  was  at- 
tained so  many  years  ago  the  extrapolated  curve  affords  a  good 
index  of  what  may  be  expected  in  the  future.  The  improbability 
of  considerably  extending  the  producing  area  is  generally  admitted 
and  it  does  not  seem  likely  that  future  discoveries  will  increase  the 
present  rate  of  production  to  any  considerable  extent. 

Extension  of  the  production  curve  indicates  that  approxi- 
mately 85  per  cent  of  the  recoverable  oil  from  New  York  and 
Pennsylvania  has  been  exhausted  under  present  operating  con- 
ditions. 

Wells  in  the  Appalachian  i-egion  are  sunk  by  the  standard  or 
churn  system  of  drilling.  The  rocks  are  hard  and  comparatively 
little  casing  is  required  as  contrasted  with  drilling  in  the  loosely 
consolidated  rocks  of  other  districts.  The  wells  range  in  depth 
from  a  few  hundred  feet  in  parts  of  eastern  Ohio  and  Kentucky  to 
between  3,000  and  4,000  feet  to  reach  the  deeper  sands  in  southern 
Pennsylvania  and  West  Virginia. 

Bradford  Sand,  Cattaraugus  and  Allegany  Counties,  N.    Y.,  and 
M^Kean  County,  Pa. 

The  Bradford  sand  is  one  of  the  longest  lived  producers  of  the 
Appalachian  district.  It  is  of  Upper  Devonian  age  and  is  encoun- 
tered at  depths  ranging  from  1,300  to  1,700  feet.  The  pay  is 
unusually  thick,  averaging  about  35  feet,  and  is  commonly  fine 


MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY 


95 


grained  and  homogeneous.  Porosity  averages  18  per  cent  by- 
volume.  The  curve  is  based  on  the  records  of  tracts  in  most 
of  which  continuous  production  data  go  back  to  the  opening  of  the 
field.  A  fair  average  of  production  for  the  entire  field  is  a  quarter 
of  a  barre'  per  well  per  day  and  many  wells  yield  only  one-tenth  of 
a  barrel  per  day.  The  curve  shows  estimated  average  future 
production  without  reference  to  flooding.  The  recent  introduc- 
tion of  the  so-called  "  water  drive  "  or  flooding  method  of  rejuve- 
nating old  properties  is  accomplishing  some  remarkable  results,  but 
records  do  not  go  back  far  enough  to  warrant  prediction  as  to 
ultimate  production. 

ESTIMATED  FUTURE  PRODUCTION  TABLE— BRADFORD  SAND 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

30 

0 

300 

2,450 

800 

4,700 

50 

250 

400 

2,950 

900 

5,050 

100 

850 

500 

3,400 

1,000 

5,400 

150 

1,400 

600 

3,8.50 

1,250 

6,100 

200 

1,800 

700 

4,300 

1,500 

6,600 

250 

2,150 

Speechly  Sand  Pool,  Concord  Township,  Butler  County,  Pa. 

The  Speechly  sand  pool  in  Concord  Township,  Butler  County, 
Pa.,  was  opened  up  in  1902,  as  the  result  of  deepening  a  well  in  an 


ESTIMATED  FUTURE  PRODUCTION  TABLE— SPEECHLY  SAND. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
.Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

B.'incls. 

50 

0 

300 

1,800 

800 

4,3.')0 

100 

350 

400 

2,550 

900 

4,6.50 

150 

700 

500 

3,150 

1,000 

4,950 

200 

1,100 

600 

3,()00 

1,2.50 

5,.5.50 

250 

1,4.50 

700 

4,000 

1,500 

6,100 

96 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 


old  Fourth  Sand  pool.  The  wells  range  between  2,200  and  2,400 
feet  in  depth  and  the  spacing  is  approximately  7  acres  per  well. 
The  sand  is  of  Upper  Devonian  age  and  varies  from  15  to  22  feet 
in  thickness.     The  oil  has  a  specific  gravity  of  about  0.800  (45°  B.) 

Hundred  Foot  Sand,  Butler  and  Allegheny  Counties,  Pa.  . 

The  Hundred  Foot  is  one  of  the  principal  sands  in  Butler  and 
Allegheny  Counties,  Pa.  The  sand  is  persistent  over  large  areas 
and  ranges  between  50  and  125  feet  in  thickness.  It  is  usually 
medium  grained,  but  is  irregularly  streaked  with  lenses  of  con- 
glomerate, which  commonly  are  the  pay  streaks  of  which  there  may 
be  several.  Production  from  the  Hundred  Foot  sand  is  charac- 
terized by  the  occurrence  of  considerable  water  which  is  pumped 
with  the  oil.  It  is  of  Upper  Devonian  age  and  is  found  at  a  depth 
of  about  1,400  feet.  The  oil  has  a  specific  gravity  of  about  0.800 
(45°  B.) 

ESTIMATED   FUTURE   PRODUCTION   TABLE— HUNDRED   FOOT 

SAND. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year." 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

300 

1,300 

800 

3,000 

100 

300 

400 

1,700 

900 

3,250 

150 

600 

500 

2,050 

1,000 

3,600 

200 

850 

600 

2,3.50 

1,250 

4,.550 

250 

1,050 

700 

2,700 

1,.500 

5,650 

Dorseyville  Thirty-foot  Pool,  Allegheny  County,  Pa. 

This  pool  was  opened  up  in  1913  and  caused  some  excitement 
because  of  its  occurrence  in  the  midst  of  old  development.  Some 
of  the  wells  had  an  initial  monthly  production  of  more  than  7,000 
barrels.  The  pay  sand — the  Thirty  Foot  of  Upper  Devonian  age 
— is  coarse  grained  and  averages  only  about  8  feet  in  thickness. 
Production  accordingly  has  fallen  off  rapidl3^  The  wells  range 
between  1,700  and  2,000  feet  in  depth.  Wells  are  irregularly 
spaced  and  (kivclopment  has  been  characterized  by  a  number  of 
dry  holes.     The  oil  has  a  specific  gravity  of  about  0  800  (45°  B.). 


MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY 


97 


ESTIMATED      FUTURE      PRODUCTION     TABLE— DORSEYVILLE 

POOL. 


Average 

Production 

per  Well 

During 

Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 

Production 

per  Well 

During 

Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 

Production 

per  Well 

During 

Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

800 

800 

2,750 

1,900 

100 

100 

900 

900 

3,000 

2,050 

150 

150 

1,000 

950 

3,500 

2,300 

200 

200 

1,250 

1,100 

4,000 

2,500 

250 

300 

1,500 

1,250 

4,500 

2,700 

300 

350 

1,750 

1,400 

5,000 

2,900 

400 

450 

2,000 

1,550 

6,000 

3,300 

500 

550 

2,250 

1,650 

7,000 

3,600 

600 

650 

2,500 

1,800 

8,000 

3,950 

700 

750 

Fifth  Sand,  Allegheny  and  Washington  Counties,  Pa. 

The  Fifth  sand  of  Upper  Devonian  age  is  one  of  the  most 
important  sands  in  the  Appalachian  region.  It  was  the  most 
productive  horizon  in  the  famous  McDonald  pool,  in  which  a  single 
well  is  credited  with  a  total  yield  of  more  than  2,000,000  barrels. 
In  Allegheny  and  Washington  Counties,  Pa.,  the  Fifth  sand  aver- 
ages between  10  and  35  feet  in  thickness,  and  like  most  of  the 
Appalachian  oil  sands  varies  considerably  in  porosity  in  nearby 
areas.     The  wells  range  between  2,200  and  2,500  feet  in  depth. 


ESTIMATED  FUTURE  PRODUCTION  TABLE— FIFTH  SAND. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

300 

2,500 

800 

5,550 

100 

700 

400 

3,250 

900 

6,050 

150 

1,200 

500 

3,850 

1,000 

6,500 

200 

1,700 

600 

4,450 

1,250 

7,600 

250 

2,100 

700 

5,000 

1,500 

8,500 

98 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 


Gordon  Sand,  Allegheny  County,  Pa. 

The  wells  average  2,100  feet  in  depth.     The  Gordon  sand  is  of 
Upper  Devonian  age. 

ESTIMATED  FUTURE  PRODUCTION  TABLE— GORDON  SAND  IN 
ALLEGHENY  COUNTY,  PA. 


Average 
Production 
per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

300 

1,300 

800 

3,450 

100 

250 

400 

1,750 

900 

3,800 

150 

500 

500 

2,250 

1,000 

4,200 

200 

750 

600 

2,700 

1,250 

5,050 

250 

1,050 

700 

3,100 

1,500 

5,800 

Gordon  Sand,  Greene  County,  Pa. 

The  Gordon  is  one  of  the  main  producing  sands  in  Greene 
County.  The  average  depth  of  wells  is  3,000  feet,  and  the  average 
thickness  of  the  pay  is  6  feet.  The  Gordon  is  of  Upper  Devonian 
age. 

ESTIMATED  FUTURE  PRODUCTION  TABLE— GORDON  SAND  IN 
GREENE  COUNTY,  PA. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

600 

2,250 

1,750 

5,250 

100 

200 

700 

2,550 

2,000 

5,800 

150 

450 

800 

2,850 

2,250 

6,400 

200 

650 

900 

3,150 

2,500 

6,950 

250 

900 

1,000 

3,450 

2,750 

7,550 

300 

1,100 

1,250 

4,050 

3,000 

8,100 

400 

1,500 

1,500 

4,650 

3,500 

9,200 

500 

1,900 

t:: 


t:= 


* 


riiv 


t^ 


IfiOO  t^OO  ZfiOO  2^P9  ^000 

^veraffG    Pracfucft'on   per"-    well    cfuring    Taxai^lG    year-,     /n    Barrels. 


111069"— 19. 


NG.  4. —ESTIMATED  AVERAGE   FUTURE   PRODUCTION   CURVES,  APPALACHIAN    FIEL 


(To  face-  pafie  99.) 


MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY 


99 


Fifty-foot  Sand,  Shinnston  Pool,  Harrison  County,  W.  Va. 

This  pool  is  credited  with  having  some  of  the  wells  of  largest 
initial  production  in  West  Virginia.  A  few  are  reported  coming  in 
at  a  rate  between  450  and  550  barrels  an  hour.  The  pool  underlies 
an  irregular  area  of  1,530  acres,  situated  on  a  terrace  on  the  western 
flank  of  the  Chestnut  Ridge  antichne.  Production  is  from  the  50- 
foot  sand.  The  pay  streak  is  of  Upper  Devonian  age  and  is  of 
variable  thickness  and  porosity,  and  averages  possibly  15  feet. 
Wells  are  between  2,000  and  2,300  feet  in  depth,  and  for  the  entire 
pool  have  an  average  spacing  of  10.7  acres  per  well.  Individual 
tracts  have  produced  at  the  rate  of  22,000  barrels  per  acre.  A 
single  well  has  yielded  more  than  165,000  barrels.  A  total  pro- 
dcction  curve  for  the  entire  pool  indicates  that  it  is  more  than  90 
per  cent  exhausted.  The  oil  has  a  specific  gravity  of  0.797 
(45.5°  B.). 

ESTIMATED  FUTURE  PRODUCTION  TABLE— SHINNSTON 

POOL. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

800 

1,100 

2,750 

4,100 

100 

50 

900 

1,300 

3,000 

4,450 

150 

150 

1,000 

1,450 

3,500 

5,200 

200 

200 

1,250 

1,900 

4,000 

5,900 

250 

250 

1,.500 

2,2.50 

4,500 

6,550 

300 

350 

1,750 

2,650 

5,000 

7,250 

400 

500 

2,000 

3,050 

6,000 

8,500 

500 

650 

2,250 

3,400 

7,000 

9,500 

600 

800 

2,500 

3,750 

7,500 

9,850 

700 

950 

Big  Injun  Sand,  Roane  County,  W.  Va. 

The  Big  Injun  sand  future  production  curve  is  based  on  the 
records  of  tracts  situated  in  different  parts  of  Roane  County, 
W.  Va.  The  sand  averages  about  40  feet  in  thickness  and  the  pay 
possibly  about  10  feet.     The  Big  Injun  sand  is  of  Lower  Car- 


MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY 


99 


Fifty-foot  Sand,  Shinnston  Pool,  Harrison  County,  W.  Va. 

This  pool  is  credited  with  having  some  of  the  wells  of  largest 
initial  production  in  West  Virginia.  A  few  are  reported  coming  in 
at  a  rate  between  450  and  550  barrels  an  hour.  The  pool  underlies 
an  irregular  area  of  1,530  acres,  situated  on  a  terrace  on  the  western 
flank  of  the  Chestnut  Ridge  anticline.  Production  is  from  the  50- 
foot  sand.  The  pay  streak  is  of  Upper  Devonian  age  and  is  of 
variab'e  thickness  and  porosity,  and  averages  possibly  15  feet. 
Wells  are  between  2,000  and  2,300  feet  in  depth,  and  for  the  entire 
pool  have  an  average  spacing  of  10.7  acres  per  well.  Individual 
tracts  have  produced  at  the  rate  of  22,000  barrels  per  acre.  A 
single  well  has  yielded  more  than  165,000  barrels.  A  total  pro- 
dcction  curve  for  the  entire  pool  indicates  that  it  is  more  than  GO 
per  cent  exhausted.  The  oil  has  a  specific  gravity  of  0.797 
(45.5°  B.). 

ESTIMATED  FUTURE  PRODUCTION  TABLE— SHINNSTON 

POOL. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

800 

1,100 

2,750 

4,100 

100 

50 

900 

1,300 

3,000 

4,450 

150 

150 

1,000 

1,450 

3,500 

5,200 

200 

200 

1,250 

1,900 

4,000 

5,900 

250 

250 

1,500 

2,250 

4,500 

6,550 

300 

350 

1,750 

2,650 

5,000 

7,250 

400 

500 

2,000 

3,050 

6,000 

8,500 

500 

650 

2,250 

3,100 

7,000 

9,500 

600 

800 

2,500 

3,750 

7,500 

9,850 

700 

950 

Big  Injun  Sand,  Roane  County,  W.  Va. 

The  Big  Injun  sand  future  production  curve  is  based  on  the 
records  of  tracts  situated  in  different  parts  of  Roane  County, 
W.  Va.  The  sand  averages  about  40  feet  in  thickness  and  the  pay 
possibly  about  10  feet.     The  Big  Injun  sand  is  of  Lower  Car- 


100 


MANUAL   FOR   THE  OIL   AND   GAS   INDUSTRY 


boniferoiis  age  and  is  found  in  this  county  at  an  average  depth  of 
2,000  feet. 


ESTIMATED  FUTURE  PRODUCTION  TABLE,  BIG    INJUN  SAND, 
ROANE  COUNTY,  W.  VA. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

600 

1,950 

1,750 

5,400 

100 

200 

700 

2,300 

2,000 

6,100 

150 

400 

800 

2,600 

2,250 

6,750 

200 

550 

900 

2,950 

2,500 

7,400 

250 

750 

1,000 

3,250 

2,750 

8,050 

300 

900 

1,250 

4,050 

3,000 

8,650 

400 

1,250 

1,500 

4,750 

3,500 

9,700 

500 

1,600 

Berea  Sand,  Lincoln  County,  W.  Va. 

The  wells  tapping  the  Berea  sands  in  Lincoln  County,  W.  Va., 
range  from  2,000  to  2,600  feet  in  depth,  and  the  sand  averages  pos- 
sibly 20  feet  in  thickness.  The  Berea  sand  is  of  Lower  Carbon- 
iferous age. 


ESTIMATED  FUTURE  PRODUCTION  TABLE,   BEREA  SAND, 
LINCOLN  COUNTY,  W.  VA. 


Average 
Production 

per  Well 
During  Last 

Taxable 
Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Last 

Taxable 
Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Last 

Taxable 
Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

600 

2,600 

2,000 

5,550 

100 

450 

700 

2,850 

2,250 

0,050 

150 

750 

800 

3,100 

2,500 

6,550 

200 

1,050 

900 

3,350 

2,750 

7,000 

250 

1,300 

1,000 

3,550 

3,000 

7,450 

300 

1,500 

1,250 

4,050 

3,500 

8,250 

400 

1,900 

1,500 

4,600 

4,000 

8,900 

500 

2,250 

1,750 

5,100 

1 

MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY 


101 


Gordon  Sand,  Wetzel  County,  W.  Va. 

The  Gordon  sand  is  the  source  of  much  oil  in  Wetzel  County. 
The  average  depth  of  wells  is  3,100  feet  and  the  average  thickness 
of  the  pay  is  7  feet.     The  Gordon  sand  is  of  Upper  Devonian  age. 

ESTIMATED  FUTURE  PRODUCTION  TABLE,  GORDON  SAND  IN 
WETZEL  COUNTY,  W.  VA. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

600 

2,350 

2,000 

5,950 

100 

250 

700 

2,700 

2,250 

6,500 

150 

450 

800 

3,050 

2,750 

7,400 

200 

700 

900 

3,350 

3,000 

7,800 

250 

900 

1,000 

3,650 

3,500 

8,550 

300 

1,150 

1,250 

4,250 

4,000 

9,300 

400 

1,550 

1,500 

4,900 

500 

1,950 

1,750 

5,400 

Berea  Sayid,  Jefferson,  Belmont,  and  Monroe  Counties,  Ohio. 

Only  a  few  records  of  Berea  sand  production  extending  over  a 
number  of  years  were  obtained  in  eastern  Ohio.  The  curve  shown 
is  based  on  the  records  of  properties  situated  in  Jefferson,  Belmont, 
and  Monroe  Counties.  The  pay  sand  is  about  20  feet  thick  and 
the  wells  range  from  1,400  to  2.000  feet  in  depth. 


ESTIMATED   FUTURE   PRODUCTION   TABLE,   BEREA   SAND   IN 
JEFFERSON,  BELMONT,  AND  MONROE  COUNTIES,  OHIO. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Y'ear. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Y'ear. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

300 

1,050 

800 

2,725 

100 

200 

400 

1,450 

900 

3,000 

150 

450 

500 

1,800 

1,000 

3,500 

200 

650 

600 

2,150 

1,2.50 

3,8.50 

250 

850 

700 

2,450 

1,500 

4,450 

102 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY 


Keener  Sand,  Jackson  Ridge  Pool  Monroe  County,  Ohio. 

The  sand  is  between  25  and  40  feet  thick  and  the  pay  averages 
12  feet.  The  wells  are  not  large  producers,  but  they  have  "  good 
staying  qualities."  They  average  1,450  feet  in  depth.  The 
Keener  sand  is  of  Lower  Carboniferous  age. 


ESTIMATED  FUTURE  PRODUCTION  TABLE— JACKSON  RIDGE 

POOL. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

300 

2,050 

800 

4,700 

100 

450 

400 

2,700 

900 

5,100 

150 

900 

500 

3,300 

1,000 

5,550 

200 

1,275 

600 

3,800 

1,250 

6,550 

250 

1,650 

700 

4,250 

1,500 

7,500 

Keener  Sand,  St.  Mary's  Pool,  Washington  County.  Ohio. 

The  pay  is  8  feet  thick  and  the  wells  average  1,650  feet  in 
depth. 


ESTIMATED  FUTURE  PRODUCTION  TABLE— ST.  MARY'S 

POOL. 


Average 
Production 
per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

800 

1,700 

2,750 

3,650 

100 

150 

900 

1,850 

3,000 

3,850 

150 

300 

1,000 

2,000 

3,500 

4,250 

200 

450 

1,250 

2,300 

4,000 

4,600 

250 

600 

1,500 

2,550 

4,500 

4,955 

300 

750 

1,750 

2,750 

5,000 

5,200 

400 

1,000 

2,000 

3,000 

6,000 

5,750 

500 

1,250 

2,250 

3,200 

7,000 

6,220 

600 

1,400 

2,500 

3,450 

8,000 

6,700 

700 

1,600 

MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY 


103 


Clinton  Sand,  Gore  Pool,  Perry  and  Hocking  Counties,  Ohio. 

The  Gore  pool  in  the  Chnton  sand  in  Perry  and  Hocking 
Counties.  Ohio,  was  opened  up  in  1911.  It  is  a  westward  exten- 
sion of  the  New  Straitsville  pool.  Up  to  1918,  134  wells  had  been 
drilled  in  the  Gore  pool  with  an  average  spacing  of  approximately 
10  acres  per  well.  The  pay  sand  ranges  from  3  to  25  feet  in  thick- 
ness and  averages  about  15  feet.  The  wells  are  between  2,900  and 
3,300  feet  deep.  The  oil  has  a  gravity  of  46°  Baumc.  The  Clinton 
sand  is  of  Silurian  age. 


ESTIMATED  FUTURE  PRODUCTION  TABLE— GORE  POOL. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

800 

1,100 

2,750 

3,550 

100 

50 

900 

1,250 

3,000 

3,800 

150 

150 

1,000 

1,400 

3,500 

5,300 

200 

200 

1,250 

1,750 

4,000 

4,700 

250 

300 

1,500 

2,100 

4,500 

5,100 

300 

350 

1,750 

2,450 

5,000 

5,500 

400 

500 

2,000 

2,750 

6,000 

6,200 

500 

6.50 

2,250 

3,000 

7,000 

0,900 

600 

800 

2,500 

3,300 

8,000 

7,550 

700 

950 

Clinton  Sand,  Wayne  and  Hocking  Couyities,  Ohio 


The  walls  vary  in  depth  between  3,000  and  3,500  feet  and  the 
average  thickness  of  the  pay  sand  is  20  feet.  The  Clinton  sand  is  of 
Silurian  age. 


104 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY 


ESTIMATED    FUTURE    PRODUCTION    TABLE— CLINTON    SAND, 
HOCKING  AND  WAYNE  COUNTIES,  OHIO. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

800 

1,100 

2,750 

4,200 

100 

50 

900 

1,300 

3,000 

4,450 

150 

75 

1,000 

1,450 

3,500 

5,050 

200 

100 

1,250 

1,950 

4,000 

5,550 

250 

150 

1,500 

2,350 

4,500 

6,050 

300 

200 

1,750 

2,750 

5,000 

6,500 

400 

350 

2,000 

3,150 

6,000 

7,400 

500 

500 

2,250 

3,550 

7,000 

8,200 

600 

700 

2,500 

3,850 

8,000 

8,900 

700 

900 

Ragland  Field,  Bath  County,  Ky. 

The  field  was  discovered  in  1900  and  was  mainly  drilled  up  by 
1904,  though  occasional  sporadic  drilling  is  still  done.  The  sand  is 
the  Corniferous  limestone  of  Devonian  age,  which  averages  from  12 
to  20  feet  in  thickness.  Its  depth  is  300  to  380  feet  in  the  Licking 
River  Valley  and  500  feet  more  on  the  hilltops.  The  oil  occurs  in  a 
flat  anticline  with  northeast-southwest  axis  and  with  the  oil  in  that 
portion  of  the  sand  lying  between  250  and_300  feet  above  sea  level. 
The  general  dip  of  the  rock  is  to  the  southeast,  and  a  few  miles  to 
the  northwest  of  the  field  the  oil  sand  crops  out  at  the  surface. 
These  is  very  little  gas  with  the  oil.  The  gravity  is  about  26°  to 
27°  Baume. 

ESTIMATED  FUTURE  PRODUCTION  TABLE— RAGLAND  POOL 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Ta.x- 
able  Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

400 

1,850 

1,000 

4,050 

100 

300 

500 

2,300 

1,250 

4,750 

150 

600 

600 

2,750 

1,500 

5,400 

200 

850 

700 

3,100 

1,750 

6,000 

250 

1,100 

800 

3,450 

2,000 

0,400 

300 

1,400 

900 

2,750 

3,000 

6,900 

MANUAL   FOR   THE  OIL  AND   GAS   INDUSTRY 


105 


Floyd  County,  Ky. 

The  future  production  curve  of  Floyd  County,  Ky.,  Is  based  on 
production  from  properties  representing  several  sands  of  Carbonif- 
erous age.  These  arc  the  Beaver,  Horton,  Pike  or  Mason,  and  the 
Salt  sands.  There  are  no  pronounced  surface  structures;  oil  and 
gas  moving  northwestward  up  the  dip  have  apparently  been 
stopped  either  by  slight  terraces  or  by  tight  places  in  the  sand. 
Dry  holes  are  numerous.  Initial  production  is  small  but  is  well 
maintained.     The  gravity  is  about  40°  Baume. 


ESTIMATED  FUTURE  PRODUCTION  CURVE, 
FLOYD  COUNTY,   KY. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

400 

1,800 

1,000 

4,950 

100 

250 

500 

2,300 

1,250 

6,300 

150 

500 

600 

2,850 

1,500 

7,600 

200 

750 

700 

3,400 

1,750 

8,700 

250 

1,050 

800 

3,900 

2,000 

9,750 

300 

1,300 

900 

4,450 

Beaver  Creek  Sand,  Wayne  County,  Ky. 

The  Wayne  County  field  consists  of  a  number  of  small  pools  to 
which  separate  local  names  are  given.  The  earliest  wells  were 
drilled  between  20  and  25  years  ago,  and  some  drilling  is  still  going 
on.  The  principal  oil-bearing  horizon  is  a  cherty  geodal  limestone 
known  as  the  Beaver  Creek  sand.  It  lies  just  above  the  Chatta- 
nooga shale  and  fornis  the  basal  number  of  the  Waverly  or  Missis- 
sippian.  This  limestone  varies  greatly  in  thickness,  texture,  and 
porosity,  and  the  production  of  wells  varies  accordingly.  It  lies 
400  to  600  feet  beneath  the  valleys,  while  the  hills  rise  from  300  to 
600  feet  higher.  Structurally  the  oil  favors  the  sides  and  bot- 
toms of  synclinal  troughs  that  slope  gently  eastward. 


106 


MANUAL  FOR  THE   OIL   AND   GAS   INDUSTRY 


ESTIMATED  FUTURE  PRODUCTION  TABLE, 
WAYNE  COUNTY,  KY. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

800 

1,450 

3,000 

3,850 

100 

100 

900 

1,600 

3,500 

4,300 

150 

250 

1,000 

1,750 

4,000 

4,700 

200 

350 

1,250 

2,050 

4,500 

5,100 

250 

450 

1,500 

2,350 

5,000 

5,450 

300 

550 

1,750 

2,650 

6,000 

6,200 

400 

750 

2,000 

2,900 

7,000 

6,900 

500 

950 

2,250 

3,150 

8,000 

7,600 

600 

1,150 

2,500 

3,400 

700 

1,300 

2,750 

3,600 

Irvine  Field,  Estill  County,  Ky. 

The  Irvine  field  extends  from  near  Irvine,  Estill  County,  Ky., 
northeastward  12  miles  and  is  1  to  2  miles  wide.  Present  evelop- 
ment  began  in  1915.  The  field  lies  on  the  southeast  of  a  fault  from 
which  the  rocks  dip  to  the  southeast.     The  producing  sand  is  a 


ESTIMATED  FUTURE  PRODUCTION  TABLE— IRVINE  POOL. 


Average 
Production 

per  Well 

During  Last 

Taxable 

Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Last 

Taxable 
Y'ear. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 

During  Last 

Taxable 

Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

800 

1,000 

3,000 

2,250 

100 

150 

900 

1,100 

3,500 

2,400 

150 

250 

1,000 

1,200 

4,000 

2,550 

200 

350 

1,250 

1,350 

4,500 

2,650 

250 

450 

1,500 

1,550 

5,000 

2,750 

300 

500 

1,750 

1,700 

6,000 

2,950 

400 

650 

2,000 

1,800 

7,000 

3,100 

500 

750 

2,250 

1,950 

8,000 

3,200 

600 

850 

2,500 

2,050 

700 

950 

2,750 

2,150 

MANUAL  FOR  THE  OIL  AND  GAS   INDUSTRY  107 

porous  magnesian  limestone  of  Corniferous  (Devonian)  age,  with 
the  pay  usually  in  the  upper  few  feet.  The  sand  near  Irvine  is 
about  20  to  30  feet  thick  and  lies  only  100  to  200  feet  beneath  the 
surface  of  the  valleys,  but  in  the  hills  600  to  800  feet  deeper. 
The  gravity  of  the  oil  is  about  33°  Baume. 

FUTURE  PRODUCTION  CURVES  FOR  LIMA-INDIANA  AND 
ILLINOIS-INDIANA  FIELDS. 

The  Lima-Indiana  field  comprises  about  230,000  acres  in  north- 
western Ohio  and  about  41,000  acres  in  northeastern  Indiana. 
The  productive  areas  in  this  field  occur  in  low  domes  over  the  broad 
crest  of  the  Cincinnati  uplift,  or  in  domes  or  terraces  or  other 
minor  convexities  on  its  flanks.  The  oil  is  obtained  from  lenses  or 
discontinuous  layers  in  the  Trenton  hmestone,  where  the  original 
limestone  has  been  changed  to  a  porous  dolomite,  at  depths  varying 
with  the  distance  from  the  crest  of  the  arch,  with  the  dip  of  strata, 
and  the  depth  below  the  top  of  the  formation.  Wherever  the 
Trenton  limestone  ceases  to  be  dolomitic  it  ceases  to  be  oil  bearing. 
This  Trenton  limestone  is  from  450  to  600  feet  thick,  and  the  oil  is 
usually  found  within  100  feet  of  the  top,  although  in  a  few  places, 
as  in  Grant  and  Delaware  Counties,  Ind.,  and  Seneca  County, 
Ohio,  oil  has  been  found  as  low  as  250  to  400  feet  in  the  Trenton. 
The  best  pay,  however,  is  generally  believed  to  be  less  than  40  feet 
below  the  top  of  the  formation.  Often  two  pay  streaks  occur  in 
the  upper  part  of  the  Trenton,  the  first  10  to  15  feet  below  the  top 
and  the  second  about  20  feet  lower.  It  seems  that  the  productive 
lenses  found  at  greater  depth  do  not  occur  at  definite  levels. 

The  existence  of  oil  in  the  Trenton  limestone  of  Ohio  was  dis- 
covered in  1885  and  many  wells  were  drilled  the  following  year. 
The  earlier  developments  were  at  Findlay  in  Hancock  County, 
North  Baltimore  in  Wood  County,  and  Lima  in  Allen  County. 
The  greater  part  of  the  production  has  come  from  Wood,  San- 
dusky, and  Hancock  Counties,  but  Allen,  Mercer,  Auglaize,  Lucas, 
Ottawa,  Seneca,  Van  Wert,  and  Darke  Counties  have  also  con- 
tributed important  quantities. 

The  finding  of  oil  in  northwest  Ohio  in  1885  stunulatcd  prospect- 
ing farther  west  in  Indiana.  In  1889  two  producing  wells  were 
drilled  in  Blackford  County  and  in  1890  several  wells  were  brought 
in  in  Wells  County,  and  from  that  date  the  field  was  rapidly  ex- 


108  MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY 

tended.  The  greater  part  of  the  Trenton  oil  production  in  Indiana 
has  come  from  Adams,  Blackford,  Delaware,  Grant,  Huntington, 
Jay,  Randolph,  and  Wells  Counties.  Of  these,  Grant  County 
has  been,  perhaps,  the  greatest  producer. 

The  pools  in  the  Trenton  rock  district  are  very  irregular  in 
shape,  differ  greatly  in  size,  and  often  entirely  surround  barren 
areas.  While,  of  course,  the  varying  characteristics  of  the  pools 
do  not  follow  arbitrary  lines,  it  was  found  best  in  making  a  study 
of  this  district  to  make  each  county  a  pool  unit. 

The  main  Illinois-Indiana  field  is  about  70  miles  long  and  has  a 
maximum  width  of  about  20  miles.  It  extends  in  a  slightly  north- 
west-southeast direction  from  the  vicinity  of  Westfield  in  north- 
western Clark  County  through  Clark,  Crawford,  and  Lawrence 
Counties  to  the  neighborhood  of  St.  Francisville.  These  are 
outliers  or  extensions  in  Coles,  Cumberland,  and  Jasper  Counties, 
but  the  three  first  named  have  produced  by  far  the  greater  portion 
of  the  oil. 

In  Indiana  the  field  extends  across  the  Wabash  River  into  Gib- 
son, Pike,  and  Sullivan  Counties. 

Nearly  all  the  production  is  found  in  structural  undulations  on 
the  east  flank  of  the  La  Salle  anticline,  which  begins  near  La  Salle 
in  the  northern  part  of  the  State  and  follows  generally  the  trend  of 
production  as  given  above.  This  great  arch  is  asymmetrical,  the 
western  limb  being  much  more  steeply  inclined  than  the  eastern. 
In  the  southern  part  of  Lawrence  County  it  appears  to  flatten  out, 
and  a  few  miles  below  St.  Francisville  it  breaks  up  and  disappears. 

Development  in  eastern  Illinois  began  with  a  well  drilled  near 
Casey,  in  Clark  County,  which  produced  about  35  barrels  a  day 
from  a  sand  found  at  a  depth  of  less  than  400  feet.  This  was  in 
1904,  and  by  the  end  of  1905  more  than  a  thousand  barrels  a  day 
were  being  marketed.     From  this  on  development  has  been  rapid. 

The  producing  sands  in  the  north  end  of  the  field  are  shallow, 
occurring  in  the  Pennsylvanian  series  at  depths  of  from  300  to 
400  feet.  Farther  south  productive  sands  are  found  much  lower 
stratigraphically,  and  lie  at  greater  depths — the  deeper  ones 
occurring  in  the  Chester  and  St.  Genevieve  (Upper  Mississippian) 
formations. 

The  richest  oil-producing  area  in  the  field  is  in  Lawrence  County 
where  seven  sands  arc  encountered  at  depths  ranging  from  450  to 
2,000  feet,  with  the  richest  sand  on  the  bottom. 


MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY  109 

Besides  the  field  on  the  slopes  of  the  La  Salle  anticline  there  are 
three  or  four  minor  pools  on  the  western  side  of  the  great  Illinois 
basin — those  of  Sandoval  in  Marion  County,  and  Carlyle  in  Clin- 
ton County,  perhaps  being  the  best  known.  Besides  those  there 
are  the  Allendale  pool  in  Wabash  County  and  the  Colmar  pool  in 
McDonough  County  which  have  produced  considerable  quantities 
of  oil. 

Productive  areas,  like  those  elsewhere,  are  irregular  in  shape  and 
of  varying  characteristics.  It  was  found  that  separation  into 
county  "  pool  units  "  as  in  the  Lima-Indiana  field  was  not  feasible, 
as  there  are  sometimes  two  or  three  variant  pools  in  a  county.  In 
some  cases,  however,  as  in  Crawford  County,  two  or  three  or  more 
"  pools "  of  the  same  general  character  were  combined  into 
one. 

In  Clark  County  there  are  two  pools,  both  in  the  shallow  Penn- 
sylvanian  sands — the  Westfield  pool  on  the  north  and  the  John- 
son Township  pool  south  and  east  of  the  Westfield.  Immediately 
to  the  southwest  of  the  Westfield  pool  and  west  of  the  Johnson 
Township  pool  Hes  the  Siggins  pool,  which  is  almost  all  in  Cum- 
berland County. 

In  Crawford  County  are  a  number  of  small  pools  without  much 
difference,  and  of  these  have  been  grouped  together  the  Robinson, 
Kibbie,  Oblong,  Honey  Creek,  and  Hardinsville,  under  the  name 
"  Robinson  pool."  In  southeast  Crawford  County  there  are  three 
outlying  pools,  Duncanville,  Flat  Rock,  and  Birds,  which  have 
been  grouped  together  under  the  name  of  Birds-Flat  Rock  pool. 

In  Lawrence  County  all  the  pools  in  the  upper  part  of  the 
county,  Nuttall,  Applegate,  Bridgeport,  Lawrenceville,  etc.,  have 
been  grouped  as  the  Upper  Lawrence  County  pool,  and  in  the 
south  are  the  Kirkwood  and  Dennison  pools. 

Other  pools  in  Illinois  are  the  Plymouth  or  Colmar  pool  in 
McDonough  County,  the  Sandoval  pool  in  Marion  County,  the 
Carlyle  pool  in  Clinton  County,  and  the  Allendale  pool  in  Wabash 
County. 

The  work  preparatory  to  the  construction  of  estimated  future 
production  curves  in  the  producing  areas  in  the  Lima-Indiana  and 
Illinois-Indiana  fields  consisted  in  the  inspection  of  all  available 
production  records  and  the  selection  of  those  considered  typical  of 
the  various  pools  and  localities,  the  tabulation  of  these  records, 
drawing  of  dechne  curves  for  individual  leases,  and  finally  the  com- 


110  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

bination  of  all  these  decline  curves  into  an  average  decline  curve 
for  the  field  or  pool. 

In  the  Lima-Indiana  field  were  found  very  few  records  of  pro- 
duction prior  to  1908.  Some  companies  had  never  kept  proper 
records  and  other  had  destroyed  all  their  old  books,  so  the  work 
was  somewhat  handicapped  in  this  regard.  However,  the  pro- 
duction records  for  the  past  10  years  were  very  full  and  complete, 
and  it  is  on  these  records  that  curves  are  based. 

The  "  average  well  "  was  adopted  as  the  unit  for  tabulation  and 
estimating  and  the  "  average  decline  curve,"  which  seems  to  meet 
all  the  requirements  of  the  situation,  was  devised  for  use  in  extend- 
ing the  individual  lease  production  curves  to  their  limit  of  profit- 
able production,  and  also  in  constrcting  the  estimated  future 
production  curve. 

In  the  Illinois-Indiana  field,  which  is  younger  than  the  Lima- 
Indiana  field,  were  found  excellent  production  records  from  the 
early  life  of  the  field.  The  same  methods  in  handling  the  records 
were  used  as  in  the  Lima-Indiana  field  and  the  same  kind  of  curves 
drawn. 

In  all  the  records  of  more  than  2,000  leases,  comprising  about 
40  per  cent  of  the  producing  area,  were  tabulated  and  studied  and 
the  resultant  curves  as  presented  herewith  are  believed  to  be  fairly 
representative. 


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A^'erage.  Production  per  ive/l  during   Ta?<able    Vear .   in  Barr&.(S^. 

FIG.  5.— ESTIMATED  AVERAGE  FUTURE  PRODUCTION  CURVES.   LIMA-INDIANA  FIELD. 


(To  (ace  page  110.) 


MANUAL   FOR   THE   OIL   AND   GAS   LNDUSTRY 

TABLES  FOR  ESTIMATION  OF  FUTURE  PRODUCTION. 
Sandusky  County,  Ohio. 


Ill 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

350 

1,350 

650 

1,970 

100 

450 

400 

1,470 

700 

2,055 

150 

700 

450 

1,575 

750 

2,150 

200 

875 

500 

1,680 

800 

2,230 

250 

1,050 

550 

1,775 

300 

1,200 

600 

1,875 

Ottawa  and  Lucas  Counties,  Ohio. 


50 

0 

350 

1,230 

650 

1,760 

100 

350 

400 

1,370 

700 

1,820 

150 

575 

450 

1,470 

750 

1,875 

200 

765 

500 

1,555 

800 

1,920 

250 

930 

550 

1,625 

300 

1,085 

600 

1,695 

Wood  County,  Ohio. 


50 

0 

400 

1,480 

1,000 

2,875 

100 

350 

450 

1,625 

1,100 

3,055 

150 

600 

500 

1,760 

1,200 

3,250 

200 

825 

600 

2,015 

1,300 

3,425 

250 

1,010 

700 

2,255 

1,400 

3,600 

300 

1,175 

800 

2,475 

1,500 

3,780 

350 

1,330 

900 

2,675 

1,550 

3,950 

Seneca  County,  Ohio. 


75 

0 

450 

1,500 

850 

1,625 

100 

260 

500 

1,640 

900 

2,750 

150 

480 

550 

1,785 

950 

2,875 

200 

675 

600 

1,930 

1,000 

3,015 

250 

870 

050 

2,075 

1 ,050 

3,140 

300 

1,025 

700 

2,220 

1,100 

3,200 

350 

1,175 

750 

2,350 

1,150 

3,400 

400 

1,350 

800 

2,475 

1,200 

3,520 

MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY 

TABLES  FOR  ESTIMATION  OF  FUTURE  PRODUCTION. 

Sandusky  County,  Ohio. 


Ill 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

350 

1,350 

650 

1,970 

100 

450 

400 

1,470 

700 

2,055 

150 

700 

450 

1,575 

750 

2,150 

200 

875 

500 

1,680 

800 

2,230 

250 

1,050 

550 

1,775 

300 

1,200 

600 

1,875 

Ottawa  and  Lucas  Counties 

Ohio. 

50 

0 

350 

1,230 

650 

1,760 

100 

350 

400 

1,370 

700 

1,820 

150 

575 

450 

1,470 

750 

1,875 

200 

765 

500 

1,555 

800 

1,920 

250 

930 

550 

1,625 

300 

1,085 

600 

1,695 

Wood  County,  Ohio. 


50 

0 

400 

1,480 

1,000 

2,875 

100 

350 

450 

1,625 

1,100 

3,055 

150 

600 

500 

1,760 

1,200 

3,250 

200 

825 

600 

2,015 

1,300 

3,425 

250 

1,010 

700 

2,255 

1,400 

3,600 

300 

1,175 

800 

2,475 

1,500 

3,780 

350 

1,330 

900 

2,675 

1,550 

3,950 

Seneca  County,  Ohio. 


75 

0 

450 

1,500 

850 

1,625 

100 

260 

500 

1,640 

900 

2,750 

150 

480 

550 

1,785 

950 

2,875 

200 

675 

600 

1,930 

1,000 

3,015 

250 

870 

650 

2,075 

1,050 

3,140 

300 

1,025 

700 

2,220 

1,100 

3,200 

350 

1,175 

750 

2,350 

1,150 

3,400 

400 

1,350 

1 

800 

2,475 

1,200 

3,520 

112 


MANUAL   FOR  THE  OIL  AND   GAS   INDUSTRY 


TABLES  FOR  ESTIMATION  OF  FUTURE  PRODUCTION— Corjt. 
Hancock  County,  Ohio. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

50 
100 
150 

200 

Barrels. 

0 
360 

670 
950 

Barrels. 

250 
300 
350 
400 

Barrels. 
1,215 

1,450 
1,685 
1,910 

Barrels. 

450 
500 

Barrels. 

2,130 
2,350 

Allen  County,  Ohio. 


50 

0 

175 

570 

300 

825 

75 

160 

200 

640 

325 

850 

100 

300 

225 

700 

350 

870 

125 

405 

250 

760 

375 

890 

150 

490 

275 

795 

400 

905 

Merceh  County,  Ohio. 


50 

0 

350 

1,030 

650 

1,475 

100 

320 

400 

1,120 

700 

1,525 

150 

525 

450 

1,205 

750 

1,580 

200 

690 

500 

1,285 

800 

1,630 

250 

825 

550 

1,350 

300 

940 

600 

1,415 

Van  Wert  County,  Ohio. 


50 

0 

125 

120 

200 

350 

75 

20 

150 

195 

225 

420 

100 

60 

175 

280 

250 

490 

Adams,  Jay,  and  Blackford  Counties,  Ind. 

50 

0 

350 

950 

800 

2,080 

100 

125 

400 

1,120 

900 

2,210 

150 

290 

450 

1,275 

1,000 

2,325 

200 

450 

500 

1,425 

1,100 

2,420 

250 

600 

600 

1,700 

1,200 

2,475 

300 

775 

700 

1,925 

:^: 


-A 


isti- 


ATED 


11106!!"— 10. 


Average  Producfion  per  yvel/   during    Taxable    Year,    in  Barrels. 

F;G.  6.— ESTIMATED  AVERAGE  FUTURE   PRODUCTION  CURVES,   ILLINOIS-INDIANA    FIELD. 


(To  face  page  113.) 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY 


113 


TABLES  FOR  ESTIMATION  OF  FUTURE  PRODUCTION— Conf. 
Grant  County,  Ind. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

300 

340 

550 

1,200 

100 

20 

350 

480 

600 

1,400 

150 

60 

400 

650 

650 

1,610 

200 

V  135 

450 

820 

700 

1,800 

250 

220 

500 

1,010 

Huntington  County,  Ind. 


50 

0 

155 

210 

250 

405 

75 

80 

175 

260 

275 

450 

100 

110 

200 

305 

300 

495 

125 

160 

225 

355 

Carlyle  and  Sandoval  Pools,  Clinton  and  Marion  Counties,  III. 


50 

0 

350 

280 

1,250 

1,800 

100 

50 

400 

340 

1,500 

2,375 

150 

90 

450 

400 

1,750 

2,975 

200 

140 

500 

460 

2,000 

3,600 

250 

175 

750 

840 

2,250 

4,250 

300 

230 

1,000 

1,280 

2,400 

4,650 

Westfield  Pool 

Clark  County,  III. 

75 

0 

400 

1,190 

1,000 

2,225 

100 

150 

450 

1,300 

1,250 

2,470 

150 

375 

500 

1,420 

1,500 

2,660 

200 

575 

600 

1,640 

1,750 

2,840 

250 

750 

700 

1,825 

2,000 

2,990 

300 

900 

800 

1,975 

2,250 

3,120 

350 

1,050 

900 

2,120 

MANUAL  FOR  THE   OIL   AND   GAS   INDUSTRY 


113 


TABLES  FOR  ESTIMATION  OF  FUTURE  PRODUCTION.— Co«/. 
Grant  County,  Ind. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

300 

340 

550 

1,200 

100 

20 

350 

480 

600 

1,400 

150 

60 

400 

650 

650 

1,610 

200 

*  135 

450 

820 

700 

1,800 

250 

220 

500 

1,010 

Huntington  County,  Ind. 


50 

0 

155 

210 

250 

405 

75 

80 

175 

260 

275 

450 

100 

110 

200 

305 

300 

495 

125 

160 

1 

225 

355 

Carlyle  and  Sandoval  Pools,  Clinton  and  Marion  Counties,  III. 


50 

0 

350 

280 

1,250 

1,800 

100 

50 

400 

340 

1,500 

2,375 

150 

90 

450 

400 

1,750 

2,975 

200 

140 

500 

460 

2,000 

3,600 

250 

175 

750 

840 

2,250 

4,250 

300 

230 

1,000 

1,280 

2,400 

4,650 

Westfield  Pool 

Clark  County,  III. 

75 

0 

400 

1,190 

1,000 

2,225 

100 

150 

450 

1,300 

1,250 

2,470 

150 

375 

500 

1,420 

1,500 

2,660 

200 

575 

600 

1,640 

1,750 

2,840 

250 

750 

700 

1,825 

2,000 

2,990 

300 

900 

800 

1,975 

2,250 

3,120 

350 

1,050 

900 

2,120 

114 


MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY 


TABLES  FOR  ESTIMATION  OF  FUTURE  PRODUCTON— Con<. 
Johnson  Pool,  Clark  County,  III. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

75 

0 

400 

1,475 

1,000 

3,440 

100 

100 

450 

1,700 

1,250 

4,025 

150 

350 

500 

1,880 

1,500 

4,500 

200 

600 

600 

2,250 

1,750 

4,950 

250 

820 

700 

2,600 

2,000 

5,360 

300 

1,025 

800 

2,900 

2,250 

5,740 

350 

1,250 

900 

3,170 

Siggins  Pool,  Cumberland  County,  III. 

75 

0 

1,000 

4,750 

3,500 

11,000 

100 

100 

1,250 

5,700 

4,000 

11,950 

200 

550 

1,500 

6,000 

4,500 

12,900 

300 

1,000 

1,750 

7,400 

5,000 

14,000 

400 

1,600 

2,000 

8,100 

6,000 

16,000 

500 

2,200 

2,500 

9,200 

7,000 

17,750 

750 

3,600 

3,000 

10,175 

8,000 

19,150 

Robinson  Pool,  Crawford  County,  III. 


100 

0 

450 

1,650 

1,250 

4,200 

150 

240 

500 

1,850 

1,500 

4,725 

200 

500 

600 

2,275 

1,750 

5,200 

250 

750 

700 

2,625 

2,000 

5,650 

300 

975 

800 

2,950 

2,250 

6,075 

350 

1,200 

900 

3,275 

400 

1,450 

1,000 

3,550 

. 

Birds-Flatrock  Pool, 

Crawford  County,  III. 

100 

0 

450 

1,125 

1,250 

2,525 

150 

350 

500 

1,240 

1,500 

2,910 

200 

450 

600 

1,450 

1,750 

3,300 

250 

600 

700 

1,625 

2,000 

3,075 

300 

750 

800 

1,800 

2,2.50 

4,035 

350 

890 

900 

1,975 

2,500 

4,440 

400 

1,020 

1,000 

2,135 

2,750 

4,750 

MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 


115 


TABLES  FOR  ESTIMATION  OF  FUTURE  PRODUCTION— Con<. 
Upper  Lawrence  CouNTi-,  III. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  WeU 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

150 

0 

6,000 

10,800 

18,000 

39,000 

500 

1,250 

7,000 

12,500 

20,000 

44,500 

1,000 

2,750 

8,000 

14,400 

22,000 

48,000 

1,500 

4,000 

9,000 

16,400 

24,000 

53,000 

2,000 

5,000 

10,000 

18,500 

26,000 

56,500 

3,000 

6,500 

12,000 

23,000 

28,000 

59,750 

4,000 

7,700 

14,000 

28,000 

30,000 

62,600 

5,000 

9,200 

16,000 

33,400 

32,000 

65,000 

KiRKwooD  Pool,  Lawrence  County,  III. 


150 

0 

1       1,253 

1,840 

4,000 

4,940 

200 

100 

1,500 

2,200 

4,500 

5,400 

300 

275 

1,750 

2,500 

5,000 

5,800 

400 

450 

2,000 

2,825 

6,000 

6,650 

500 

625 

2,500 

3,400 

7,000 

7,450 

750 

1,040 

3,000 

3,970 

8,000 

8,225 

1,000 

1,470 

3,500 

4,470 

Dennison  Pool,  Lawrence  County,  III. 

150 

0 

6,000 

13,400 

18,000 

41,000 

500 

1,500 

7,000 

15,000 

20,000 

46,700 

1,000 

3,000 

8,000 

17,000 

22,000 

52,000 

1,500 

4,500 

9,000 

19,000 

24,000 

56,700 

2,000 

6,000 

10,000 

21,000 

26,000 

60,700 

3,000 

8,200 

12,000 

25,500 

28,000 

64,000 

4,000 

10,000 

14,000 

30,400 

30,000 

67,000 

5,000 

11,800 

16,000 

35,500 

32,000 

69,800 

Plymouth  Pool,  Mc 

Donough  County,  III. 

50 

0 

450 

400 

1,500 

1,275 

100 

50 

500 

450 

1,750 

1,460 

150 

100 

600 

550 

2,000 

1,630 

200 

150 

700 

640 

2,500 

1,950 

250 

200 

800 

725 

3,000 

2,200 

300 

250 

900 

820 

4,000 

3,200 

350 

300 

1,000 

900 

5,000 

4,500 

400 

350 

1.2.50 

1,100 

116 


MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY 


TABLES  FOR  ESTIMATION  OF  FUTURE  PRODUCTION— Co/rf. 

Gibson  County,  Ind. 


Average 
Production 
per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
I)er  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

50 

0 

300 

885 

550 

1,775 

100 

175 

350 

1,065 

600 

1,950 

150 

355 

400 

1,240 

650 

2,130 

200 

530 

450 

1,425 

700 

2,310 

250 

710 

500 

1,600 

Pike  County,  Ind. 


50 

0 

650 

1,175 

1,500 

2,290 

100 

125 

700 

1,250 

1,600 

2,420 

150 

250 

750 

1,325 

1,700 

2,550 

200 

375 

800 

1,380 

1,800 

2,660 

250 

500 

850 

1,450 

1,900 

2,780 

300 

600 

900 

1,520 

2,000 

2,900 

350 

700 

950 

1,590 

2,200 

3,140 

400 

800 

1,000 

1,650 

2,400 

3,370 

450 

890 

1,100 

1,775 

2,600 

3,600 

500 

960 

1,200 

1,920 

2,800 

3,825 

550 

1,040 

1,300 

2,020 

3,000 

4,050 

600 

1,100 

1,400 

2,170 

3,200 

4,250 

Sullivan  Pool,  Sullivan  County,  Ind. 

50 

0 

600 

550 

1,750 

1,750 

100 

10 

700 

675 

2,000 

1,940 

150 

40 

800 

800 

2,250 

2,125 

200 

60 

900 

925 

2,500 

2,300 

250 

100 

1,000 

1,040 

2,750 

2,475 

300 

150 

1,100 

1,150 

3,000 

2,640 

350 

200 

1,200 

1,250 

3,250 

2,800 

400 

275 

1,300 

1,335 

3,500 

2,970 

450 

350 

1,400 

1,430 

3,750 

3,125 

500 

410 

1,500 

1,525 

4,000 

3,280 

MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY  117 

FUTURE  PRODUCTION  CURVES  MID-CONTINENT  DISTRICT. 

The  oil  fields  of  the  Mid-Continent  Division  are  situated  in  a 
broad  belt  extending  from  near  Kansas  City,  south  through  eastern 
Kansas  and  northeastern  Oklahoma,  thence  southwest  through 
south-central  Oklahoma  into  northwest  Texas  as  far  as  Brown- 
wood.  Pools  are  scattered  throughout  this  area  and  new  pools 
are  being  discovered  from  time  to  time.  Nearly  all  pools  are 
located  on  geologic  structures  that  are  well  defined  at  the  surface. 
With  the  exception  of  a  few  pools  of  minor  miportance  in  southern 
Oklahoma  and  in  Texas,  all  production  is  from  formations  of  Car- 
boniferous age,  the  Pennsylvanian  scries  being  of  most  miportance. 
In  general  the  formations  dip  to  the  west  or  northwest.  There 
are  numerous  producing  sands  at  various  horizons,  and  in  some 
fields  there  are  several  productive  sands.  The  depths  to  produc- 
tion range  from  200  feet  to  3,500  feet,  the  shallow  wells  being 
generally  along  the  eastern  edge  of  the  district  and  the  deeper  wells 
confined  to  the  western  portion.  Most  of  the  production  comes 
from  true  sandstones  with  hmestone  as  a  secondary  productive 
formation.  The  thicknesses  of  the  sands  range  up  to  300  feet 
(Healdton),  but  generally  are  between  25  and  75  feet. 

The  oil  in  the  Mid-Continent  Field  is  of  paraffin  base;  from  30° 
Baume  to  45°  Baume  in  gra\4ty,  and  averages  about  35°  Bamnc. 
The  original  pressures  in  the  gas  and  oil  sands  are  roughly  pro- 
portional with  the  depths.  The  recoveries  per  acre  from  the 
Oklahoma  pools  have  been  generally  higher  than  in  the  eastern 
fields,  but  are  less  than  for  the  Gulf  coast  and  California.  Wells 
are  spaced  from  2  acres  per  well  to  12  acres  per  well,  the  average 
being  about  6  acres  per  well. 

The  wells  in  the  Mid-Continent  Fields  are  drilled  mostly  by 
standard  tools,  rotary  drilling  being  confined  to  a  few  fields  in 
Texas  and  to  fields  m  the  red  beds  of  Oklahoma.  Drilling  costs  are 
greater  than  in  the  eastern  fields,  but  less  than  for  fields  still  far- 
ther west.  The  same  statement  holds  true  for  prochicing  costs, 
consequently  the  wells  can  not  be  pmnped  to  such  small  produc- 
tions as  in  the  eastern  fields,  and  unless  the  price  of  oil  increases 
considerably  in  the  future  the  wells  will  generally  not  ha\'e  such 
long  lives  as  in  the  eastern  fields,  because  the  greatest  single  factor 
in  the  longevity  of  wells  is  the  smallest  production  to  which  a  wc  11 
can  be  pumped  profitably.     Artificial  increasing  of  recovery  is 


118  MANUAL   FOR   THE  OIL  AND   GAS   INDUSTRY 

limited  practically  to  the  use  of  vacuum  pumps.  This  is  common 
and  has  made  notable  effects  on  the  productions  of  wells  and  also 
has  been  an  important  factor  in  extending  the  lives  of  the  wells  by 
making  the  operation  of  small  wells  more  profitable. 

The  present  investigation  has  brought  to  light,  in  the  case  of 
many  of  the  smaller  companies,  a  most  amazing  disregard  for 
proper  records  of  their  operations,  and  a  general  lack  of  apprecia- 
tion of  the  value  of  these  was  noted  among  most  companies.  It  is 
Ijelieved  that  even  the  larger  companies  would  find  it  profitable 
to  get  more  detailed  and  accurate  well  and  production  records,  and 
to  make  provision  for  their  study  and  use.  Most  of  the  trouble  in 
making  estimates  of  future  production  could  be  traced  to  inad- 
equate records,  rather  than  to  the  so-called  freak  wells. 

Only  the  average  future  production  curves  were  prepared  for 
publication.  These  show  what  may  be  expected  on  the  average 
from  wells  within  the  district,  to  which  each  curve  and  table 
applies.  This  does  not  mean  that  every  property  will  have  the 
same  future  for  wells  of  the  same  size,  for  it  may  vary  from  it  con- 
siderably. If  the  producer  does  not  work  out  the  projection  for 
each  of  his  properties  he  can  use  the  average  curves  as  guides  and 
know  that,  in  most  cases,  his  wells  will  approximate  the  figure 
given  and  are  just  as  likely  to  be  above  as  below  the  average 
figure.  If  the  operator  has  a  number  of  properties  in  the  district, 
the  general  average  will  probably  fall  somewhere  near  the  pub- 
lished curves.  The  possible  variations  are  also  distinctly  limited 
and  will  rarely  exceed  certain  maxima  and  minima  for  each  dis- 
trict. This  means  that  the  so-called  freaks  are  as  the  name  implies, 
rare.  In  most  fields  they  do  not  exceed  1  per  cent  and  it  is  believed 
the  number  would  be  further  reduced  were  it  possible  to  check 
over  each  record  to  its  source. 

Where  the  production  record  is  short,  confused  or  incomplete, 
the  taxpayer  may  be  compelled  to  assume  that  his  wells  are  average 
unti'  later  years  when  more  adequate  data  are  available.  Where 
better  production  records  can  be  obtained  the  taxpayer  will  find  it 
desirable  to  work  out  the  curves  for  each  property  and  thus  make 
closer  estimates  of  its  future.  This  is  work  for  the  qua'ified  engi- 
neer or  geologist  though  probably  much  can  be  done  in  future  to 
simplify  methods. 

The  average  curves  were  made  for  certain  fields  or  districts  in 
accordance  with,  first,  similar  conditions;  and  second,  the  number 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY  119 

of  usable  production  records.  The  end  sought  was  to  have  enough 
records  for  each  field  to  give  a  reliable  average  curve  and  at  the 
same  time  to  differentiate  between  fields  whose  average  curves 
would  differ  materially.  The  districts  were  worked  out  by  knowl- 
edge of  the  general  conditions  and  by  trial  to  determine  whether 
the  district  could  be  subdivided  advantageously  or  could  be  com- 
bined with  some  other  field  or  district. 

A  refinement  not  possible  in  the  present  investigation  was  the 
working  out  of  factors  for  readily  judging  how  closely  a  particular 
property  approaches  the  average  curve.  Much  can  be  done  with 
the  data  available  by  comparing  the  futures  in  relation  to  the  chief 
factors  affecting  production  in  the  niid-continent  field,  which  are: 
First,  thickness  of  sands  or  pay  streak;  second,  porosity  of  sand; 
third,  well  depths;  fourth,  well  spacing;  fifth,  manner  of  operation. 
By  proper  analysis  of  these  factors  it  is  believed  convenient  curves 
and  tables  can  be  worked  out  for  making  closer  estimations. 

Curves  for  the  older  and  more  developed  fields  such  as  Bartles- 
ville  were  easily  obtained,  but  difficulties  were  encountered  in  some 
of  the  other  fields.  In  eastern  Kansas,  few  records  were  obtain- 
able and  in  many  of  the  younger  fields  of  the  Mid-Continent,  the 
records  were  few,  short,  and  difficult  to  use.  In  some  fields,  suf- 
ficient data  to  make  curves  were  not  obtainable  and  the  curves  for 
others  will  have  to  be  used  until  more  data  are  available. 

The  north  central  Texas  oil  and  gas  field  comprises  the  follow- 
ing counties:  Jack,  Throclanorton,  Shackelford,  Stephens,  Palo 
Pinto,  Parker,  Erath,  Eastland,  Callahan,  Taylor,  Runnels,  Cole- 
man, Brown,  Comanche,  Mills,  San  Saba,  McCulloch,  and  Concho. 
Production  in  this  area  is  divided  into  several  distinct  pools,  and 
the  producing  horizons  are  found  in  rocks  ranging  in  age  from  late 
Mississippian  or  earliest  Pennsylvanian  through  the  Pennsylvanian 
and  into  the  early  Permian.  The  depth  of  the  producing  wells 
varies  from  less  than  100  feet  near  Brownwood  to  more  than  4,000 
feet  in  Palo  Pinto  County. 

Drilling  has  not  yet  progressed  far  enough  to  test  out  all  the 
area,  but  several  distinct  pools  have  been  outlined.  The  Avis 
shallow  pool  in  northern  Jack  County,  the  Millsap  pool  in  south- 
western Parker  County,  the  Grayford  pool,  the  Mineral  Wells  gas 
pool  and  the  Strawn  pool  in  Palo  Pinto  County,  the  Desdemona  and 
Sipe  Springs  pools  in  northern  Comanche  County,  the  Ranger  and 
Allen  pools  in  Eastland  County,  the  Caddo,  Brcckcnridge,  and 


120 


MANUAL   FOR  THE  OIL  AND   GAS   INDUSTRY 


Black  pools  in  Stephens  County,  the  South  Bend  pool  in  Young 
County,  the  Moran  pool  in  Shackelford  County,  the  Abilene  pool 
in  Taylor  County,  the  Gray,  Coleman,  and  Santa  Anna  pools  in 
Coleman  County,  and  the  Brownwood  pool  in  Brown  County 
show  the  wide  distribution  of  the  producing  areas.  Of  these  pools, 
the  most  important,  at  present,  are  the  Ranger,  Brackenridge, 
Caddo,  and  Desdemona  pools,  where  the  oil  is  produced  from  the 
Bend  formation  of  the  late  Mississippian  or  early  Pennsylvanian 
age. 

Because  the  development  in  this  area  has  been  recent  and  the 
production  in  many  cases  held  back  for  lack  of  storage  facilities,  it 
was  impossible  to  work  out  an  average  future  production  curve  for 
the  district  or  for  an  individual  pool. 

Eldorado  District,  Butler  County,  Kans. 

The  curves  and  tables  for  the  Eldorado  district  were  compiled 
from  data  submitted  on  leases  within  townships  25  and  26  south 
and  ranges  4  and  5  east.  Late  in  1915,  the  first  commercial  pro- 
ducer was  drilled  to  the  Shallow  sand  in  section  29,  township  25 
south,  range  5  west.  From  this  the  pool  was  rapidly  extended  in 
all  directions  and  the  deeper  sands  developed,  culminating  in  the 
discovery  and  exploitation  of  the  2,500  feet  sand  in  the  Towanda 


ESTIMATED  FUTURE  PRODUCTION  TABLE,  ELDORADO 
DISTRICT,  IvANS. 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Ta.xable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

100 

0 

8,000 

8,500 

40,000 

25,000 

500 

500 

9,000 

9,200 

45,000 

26,800 

1,000 

1,100 

10,000 

10,000 

50,000 

28,500 

1,500 

1,800 

12,500 

11,800 

60,000 

31,800 

2,000 

2,040 

15,000 

13,500 

70,000 

34,800 

2,500 

3,000 

17,500 

15,000 

80,000 

37,500 

3,000 

3,700 

20,000 

16,400 

90,000 

40,000 

4,000 

4,800 

22,500 

17,700 

100,000 

42,500 

5,000 

5,700 

25,000 

18,900 

125,000 

48,200 

0,000 

G,700 

30,000 

21,000 

150,000 

53,700 

7,000 

7,()00 

35,000 

23,100 

MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY 


121 


district  in  the  spring  and  summer  of  1917.  Water  in  the  producing 
sands  has  been  a  serious  menace  and  some  wells,  originally  large 
producers,  have  been  completely  drowned  out. 

The  structural  geology--  of  Butler  county  has  been  worked  out 
in  considerable  detail  and  shows  that  production  is  confined  to  the 
tops  and  flanks  of  well-defined  domes.  Five  producing  sands  are 
found  at  approximately  depths  of  660  feet,  750  feet,  850  feet,  1,850 
feet,  and  2,500  feet,  respectively,  and  with  thicknesses  varying 
from  10  feet  to  50  feet. 

Augusta  District,  Butler  County,  Kans. 

This  district  is  included  in  townships  27,  28,  and  29  south, 
range  4  west. 

The  field  was  discovered  in  June,  1914.  The  production  is 
from  a  sand  which  is  encountered  at  an  average  dopth  of  2,500  to 
2,600  feet,  and  has  an  average  thickness  of  approximately  30  feet. 

The  shallow  sands,  if  they  are  present,  are  not  productive. 

ESTIMATED  FUTURE  PRODUCTION  TABLE,  AUGUSTA 
DISTRICT,  IvANSAS. 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Barrels. 

500 
1,000 
2,000 
3,000 
4,000 
5,000 
6,000 
7,000 
8,000 
9,000 

Barrels. 

0 
750 
2,000 
3,200 
4,500 
5,500 
6,750 
7,800 
8,800 
9,800 

Barrels. 

10,000 
15,000 
20,000 
25,000 
30,000 
35,000 
40,000 
45,000 
50,000 
60,000 

Barrels. 

10,750 
15,000 
19,000 
22,500 
25,750 
28,800 
31,800 
34,750 
37,300 
41,7.50 

Barrels. 

70,000 
80,000 
90,000 
100,000 
110,000 
120,000 
130,000 
140,000 
150,000 
1(M),000 

Barrels. 

45,400 
48,750 
51,700 
54.500 
57,000 
59,000 
61,000 
02,750 
64,200 
65,800 

Neodesha  District,  Wilson  County,  Kans. 

The  curve  and  tables  for  the  Neodesha  district  were  compiled 
from  the  data  on  leases  lying  within  township  30  south,  range  16 
east.     The  productive  area  of  the  district  covers  a  nmch  larger 


122 


MANUAL  FOR  THE  OIL   AND   GAS   INDUSTRY 


area,  but  since  the  records  of  the  area  were  very  incomplete  else- 
where only  the  ones  within  the  above-described  township  were 
used. 

Discovery  was  made  in  this  district  about  1893  in  a  sand  mem- 
ber of  the  Cherokee  shales  which  is  equivalent  to  the  Bartlesville 
sand  of  Oklahoma.  The  sand  in  this  district  is  encountered  at  an 
average  depth  of  800  to  820  feet  and  is  16  to  22  feet  in  thickness. 

ESTIMATED  FUTURE  PRODUCTION,  NEODESHA  DISTRICT. 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Ta.xable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Barrels. 

150 
200 
250 
300 
350 
400 
450 
500 
600 
700 
800 
900 
1,000 
1,100 

Barrels. 

0 
950 
1,600 
2,100 
2,500 
2,850 
3,125 
3,350 
3,725 
4,050 
4,325 
4,575 
4,780 
4,975 

Barrels. 

1,200 
1,300 
1,400 
1,500 
1,600 
1,700 
1,800 
1,900 
2,000 
2,200 
2,400 
2,600 
2,800 
3,000 

Barrels. 

5,150 
5,280 
5,425 
5,530 
5,640 
5,730 
5,810 
5,900 
5,975 
6,100 
6,250 
6,350 
6,450 
6,560 

Barrels. 

3,200 
3,400 
3,600 
3,800 
4,000 
4,200 
4,400 
4,600 
4,800 
5,000 
6,000 
7,000 
8,000 

Barrels. 

6,060 
6,750 
6,850 
6,940 
7,030 
7,120 
7,220 
7,300 
7,390 
7,480 
7,925 
8,300 
8,700 

Bartlesville- Dewey  District,  Washington  County,  Okla. 

The  curves  and  tables  are  derived  from  property  production 
records  in  all  that  part  of  Washington  County  lying  in  the  town- 
ships 25-29  north  and  ranges  12-13  east.  The  area  includes  the 
Bartlesville,  Dewey,  Hogshooter,  Copan,  and  Canary  pools.  The 
district  is  the  oldest  in  Oklahoma,  being  opened  in  1903,  although 
most  of  the  development,  following  the  natural  extension  of  work 
from  Kansas  southward  into  Indian  Territory,  began  in  1904  and 
was  pursued  extensively  in  the  three  subsequent  years.  Several 
of  the  earlier  records  show  wells  of  300  to  400  barrels  initial  pro- 
duction. In  later  years,  however,  initial  production  is  much 
smaller.  Since  the  latter  part  of  1916  vacuum  has  been  quite 
generally  applied. 


MANUAL  FOR   THE  OIL  AND   GAS   INDUSTRY 


123 


There  are  various  producing  oil  and  gas  sands  in  the  district, 
the  principal  ones  being,  with  their  average  thickness  and  depth: 

35  feet  of  Peru  at  700  feet,  26  feet  of  Skinner  at  1,050 
feet,  32  feet  of  Bartlesville  at  1,250  feet  34  feet  of  Burgess  at 
1,340  feet. 

The  average  spacing  of  wells  is  about  one  to  each  6  acres. 

ESTIMATED  FUTURE  PRODUCTION  TABLE,  BARTLESVILLE- 
DEWEY,  HOGSHOOTER  DISTRICT. 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Keserves 

per  Well. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

Per  Well. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

100 

300 

700 

2,450 

2,500 

6,850 

150 

500 

800 

2,750 

3,000 

7,800 

200 

700 

900 

3,050 

3,500 

8,700 

250 

900 

1,000 

3,350 

4,000 

9,600 

300 

1,050 

1,250 

4,000 

4,500 

10,300 

350 

1,250 

1,500 

4,650 

5,000 

11,100 

400 

1,400 

1,750 

5,200 

6,000 

12,600 

450 

1,600 

2,000 

5,800 

7,000 

14,000 

500 

1,800 

2,250 

6,350 

8,000 

15,450 

600 

2,100 

Nowata  District,  Rogers  and  Nowata  Counties,  Okla. 

The  curves  and  tables  for  the  Nowata  district  are  made  to  cover 
townships  24  to  27  north,  inclusive,  and  parts  of  ranges  15  to  17 
east. 

They  include  the  shallow  pools  known  as  Chelsea,  Alluwe, 
Coodys  Bluff,  Childers,  Delaware,  and  Nowata.  While  conditions 
as  to  depth  and  sands  vary  somewhat  in  these  pools,  the  curves 
apply  to  all  the  region. 

Development  was  begun  in  the  Coodys  Bluff-Nowata-Alluwe 
region  in  1904.  In  1908  the  Delaware,  Childers  region  was  devel- 
oped. 

The  principal  producing  sand  is  the  Bartlesville,  found  at 
depths  varying  (according  to  location)  from  390  feet  to  something 
over  1,000  feet.  The  average  depth  in  the  AUuwe-Chelsea  pool 
being  450  feet,  at  Coodys  Bluff  525  feet,  at  Nowata  650  feet,  near 


124 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY 


Delaware  675  feet,  in  township  27  north,  ranges  14  and  15  east,  940 
feet.     The  thickness  of  the  sand  varies  from  20  to  50  feet. 

The  Tucker  sand  lying  about  100  feet  below  the  Bartlesville 
has  been  recognized  near  Coodys  Bluff  and  in  the  northwest  parts  of 
the  field. 

Wells  have  had  initial  production  as  high  as  500  barrels,  soon 
settling  to  a  very  steady  small  production.  Water  is  present,  but 
apparently  does  not  constitute  a  menace.  In  the  developed  area, 
wells  are  spaced  at  about  4  acres  per  well. 


ESTIMATED  FUTURE  PRODUCTION  TABLE,  NOWATA 
DISTRICT. 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Average 
Production 

per  Well 

for  Ta.xable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Average 
Production 

per  Well 

for  Ta.Kable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

150 

0 

700 

2,200 

2,500 

5,300 

200 

300 

800 

2,500 

3,000 

5,800 

250 

550 

900 

2,740 

3,500 

6,180 

300 

800 

1,000 

3,000 

4,000 

6,520 

350 

1,000 

1,250 

3,550 

4,500 

6,820 

400 

1,220 

1,500 

4,000 

5,000 

7,100 

450 

1,470 

1,750 

4,370 

6,000 

7,550 

500 

1,600 

2,000 

4,700 

7,000 

7,880 

600 

1,900 

2,250 

5,000 

8,000 

8,175 

Adair  Pool,  Nowata  County,  Okla. 

The  Adair  pool  is  in  the  east  half  of  townships  25  to  26  north, 
range  14  east,  and  in  parts  of  townships  25  and  26  north,  range  15 
east,  ali  in  Nowata  County.  The  producing  sand  is  the  Bartles- 
ville, found  at  an  average  depth  of  1,050  feet.  Its  thickness  varies 
from  12  to  45  feet,  with  an  average  of  30  feet.  Discovery  and  first 
development  in  this  district  was  in  1912.  Wells  drilled  in  that 
year  had  an  initial  production  as  high  as  400  barrels.  The  pro- 
duction almost  always  shows  a  very  sharp  decline  for  the  first  two 
years  followed  by  a  very  slight  decline  in  the  settled  production 
through  a  period  of  years.  Spacing  of  wells  is  about  7  acres 
per  well. 


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Average   Producfion   per    ws/l   during    Taxable    Year,    in    Barrels. 

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(To  face  page  124.) 


MANUAL  FOR  THE  OIL  AND  GAS   INDUSTRY 


125 


ESTIMATED  FUTURE  PRODUCTION  TABLE,  ADAIR  DISTRICT. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

1 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

100 

200 

700 

1,150 

2,500 

3,275 

150 

275 

800 

1,280 

3,000 

3,750 

200 

375 

900 

1,420 

3,500 

4,200 

250 

450 

1,000 

1,550 

4,000 

4,650 

300 

550 

1,250 

1,850 

4,500 

5,075 

350 

620 

1,500 

2,150 

5,000 

5,500 

400 

700 

1,750 

2,450 

6,000 

6,325 

450 

780 

2,000 

2,750 

7,000 

7,150 

500 

850 

2,250 

3,000 

8,000 

7,900 

600 

1,000 

Okesa  District,  Osage  County,  Okla. 

The  curves  and  tables  for  this  district  are  compiled  from  records 
of  the  Osage  Agency.  The  district  is  included  in  townships  26 
and  27  north,  ranges  10  and  11  east,  and  comprises  the  Okesa  pool 
and  other  production  west  of  Bartlesville.  Development  began 
in  1904  and  has  proceeded  to  the  present  time.  The  principal 
producing  sand  is  the  Bartlesville,  found  at  depths  varying  from 
1,575  to  1,900  feet,  according  to  location  and  topography,  with  an 
average  thickness  of  30  feet. 


ESTIMATED  FUTURE  PRODUCTION  TABLE— OKESA  DISTRICT. 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

.\verage 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Barrels. 

75 
150 
200 
250 
300 
350 
400 
450 
500 

Barrels. 

0 
500 
750 
1,000 
1,.300 
1,800 
1,950 
2,150 
2,440 

Barrels. 

600 

700 

800 

900 

1,000 

1,250 

1,500 

1,750 

Barrels. 

3,000 
3,400 
4,000 
4,450 
4,950 
6,000 
7,100 
8,500 

Barrels. 

2,000 
2,250 
2,500 
3,000 
3,500 
4,000 
4,500 
5,000 

Barrels. 

9,050 
9,800 
10,600 
11,900 
13,075 
14,075 
15,100 
16,000 

MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY 


125 


ESTIMATED  FUTURE  PRODUCTION  TABLE,  ADAIR  DISTRICT. 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Barrels. 

100 
150 
200 
250 
300 
350 
400 
450 
500 
600 

Barrels. 

200 
275 
375 
450 
550 
620 
700 
780 
850 
1,000 

Barrels. 

700 
800 
900 
1,000 
1,250 
1,500 
1,750 
2,000 
2,250 

Barrels. 

1,150 
1,280 
1,420 
1,550 
1,850 
2,150 
2,450 
2,750 
3,000 

Barrels. 

2,500 
3,000 
3,500 
4,000 
4,500 
5,000 
6,000 
7,000 
8,000 

Barrels. 

3,275 
3,750 
4,200 
4,650 
5,075 
5,500 
6,325 
7,150 
7,900 

Okesa  District,  Osage  County,  Okla. 

The  curves  and  tables  for  this  district  are  compiled  from  records 
of  the  Osage  Agency.  The  district  is  included  in  townships  26 
and  27  north,  ranges  10  and  11  east,  and  comprises  the  Okesa  pool 
and  other  production  west  of  Bartlesville.  Development  began 
in  1904  and  has  proceeded  to  the  present  time.  The  principal 
producing  sand  is  the  Bartlesville,  found  at  depths  varying  from 
1,575  to  1,900  feet,  according  to  location  and  topography,  with  an 
average  thickness  of  30  feet. 


ESTIMATED  FUTURE  PRODUCTION  TABLE— OKESA  DISTRICT. 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

.\verage 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Barrels. 

75 
150 
200 
250 
300 
350 
400 
450 
500 

Barrels. 

0 
500 
7,50 
1,000 
1,300 
1,800 
1,950 
2,150 
2,440 

Barrels. 

600 

700 

800 

900 

1,000 

1,250 

1,500 

1,750 

Barrels. 

3,000 
3,400 
4,000 
4,450 
4,950 
6,000 
7,100 
8,.500 

Barrels. 

2,000 
2,250 
2,500 
3,000 
3,500 
4,000 
4,500 
5,000 

Barrels. 

9,050 
9,800 
10,600 
11,900 
13,075 
14,075 
15,100 
16,000 

126 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY 


Avant-Ramona  District,  Osage  and  Washington  Counties,  Okla. 

The  curves  and  tables  of  this  district  are  derived  from  records 
of  properties  in  Osage  County  and  eastward  into  Washington 
County.  The  area  is  located  in  townships  22-23  and  24  north, 
ranges  11  and  12  east.  The  principal  producing  sands  are  the 
Peru,  at  800-1,200  feet,  and  the  Bartlesville,  at  an  average  depth 
of  1,620  feet,  the  latter  with  an  average  thickness  of  about  54  feet. 


ESTIMATED  FUTURE  PRODUCTION  TABLE— AVANT-RAMONA 

DISTRICT. 

Average 
Production 

per  Well 

for  Taxaljle 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

100 

100 

700 

2,975 

3,000 

11,350 

150 

275 

800 

3,500 

3,500 

12,520 

200 

500 

900 

4,000 

4,000 

13,700 

250 

700 

1,000 

4,500 

4,500 

14,725 

300 

900 

1,250 

5,625 

5,000 

15,600 

350 

1,125 

1,500 

6,700 

6,000 

16,915 

400 

1,350 

1,750 

7,675 

7,000 

17,780 

450 

1,610 

2,000 

8,500 

8,000 

18,425 

500 

1,900 

2,250 

9,300 

9,000 

19,000 

600 

2,410 

2,500 

10,050 

10,000 

19,350 

Cleveland  District,  Pawnee  County,  Okla. 

The  Cleveland  district  is  in  townships  20  and  21  north,  ranges  7 
and  8  east,  all  in  Pawnee  County.  No  Osage  records  were  used  in 
the  compilation,  but  it  is  considered  that  the  curve  may  apply  to 
the  extension  of  the  Cleveland  pool  into  Osage  County  and  also  to 
the  so-called  Olney  pool,  southwest  of  Cleveland.  Development 
was  begun  in  1904,  mainly  in  town-lot  drilling  in  Cleveland.  The 
principal  producing  sands  with  their  average  depth  are:  Layton, 
1,200  to  1,300  feet;  Cleveland,  1,050;  Skinner,  2,200;  Bartles- 
ville, 2,400;  and  Tucker,  2,600. 

Many  wells  formerly  producing  from  upper  sands  have  been 
deepened  to  the  last  two  named,  which  are  the  most  important 
producers.  Wells  come  in  with  high  initial  capacity  and  show  long 
life  due  to  the  thickness  of  the  Bartlesville  sand,  which  ranges  from 
30  to  95  feet.     Vacuum  has  been  quite  widely  applied  to  wells  from 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY  127 

1916  to  the  present  time.    The  spacing  is  about  6|  acres  per  well 
outside  of  the  town  drilUng. 

ESTIMATED  FUTURE  PRODUCTION  TABLE— CLEVELAND 
DISTRICT. 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Year. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estima'ed 

Recoverable 

Underground 

Reserves 

per  Year. 

-Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Year. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

500 

0 

2,500 

10,200 

11,000 

23,375 

600 

900 

3,000 

11,500 

12,000 

24,700 

700 

1,700 

3,500 

12.575 

13,000 

26,050 

800 

2,500 

4,000 

13,600 

14,000 

27,400 

900 

3,250 

4,500 

14,400 

15,000 

28,750 

1,000 

3,800 

5,000 

15,200 

16,000 

30,100 

1,250 

5,440 

6,000 

16,650 

17,000 

31,450 

1,500 

6,700 

7,000 

18,100 

18,000 

32,800 

1,750 

8,000 

8,000 

19,400 

19,000 

34,150 

2,000 

8,700 

9,000 

20,700 

20,000 

35,500 

2,250 

9,450 

10,000 

22,050 

Bird  Creek  District,  Tulsa  County,  Okla. 

The  curves  and  tables  herewith  apply  to  the  area,  all  of  which 
is  in  Tulsa  County,  in  townships  20,  21,  and  22  north,  ranges  12  to 

ESTIMATED  FUTURE  PRODUCTION  TABLE— BIRD  CREEK- 
SKIATOOK  DISTRICT. 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

.Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

100 

200 

700 

2,800 

2,500 

9,400 

150 

400 

800 

3,200 

3,000 

11,200 

200 

700 

900 

3,630 

3,500 

12,800 

250 

900 

1,000 

4,050 

4,000 

14,500 

300 

1,200 

1,250 

5,000 

4,500 

16,100 

350 

1,300 

1,500 

5,800 

5,000 

17,700 

400 

1,600 

1,750 

6,800 

6,000 

20,800 

450 

1,750 

2,000 

7,800 

7,000 

23,900 

500 

2,000 

2,250 

8,700 

8,000 

27,000 

600 

2,400 

128 


MANUAL   FOR   THE   OIL   AND   GAS   INDUSTRY 


13  east.  Included  are  the  North  Tulsa,  Flat  Rock.  Turley, 
Speriy,  and  Skiatook  pools.  The  producing  sands  are  the  Bar- 
tlesville,  at  an  average  depth  of  1,130  feet,  with  an  average  thick- 
ness of  -41  feet,  and  the  Tucker,  found  at  an  average  depth  of  1,290 
feet  and  an  average  thickness  of  28  feet.  This  is  one  of  the  oldest 
and  steadiest  producing  fields  of  Oklahoma.  Development  began 
in  1906  and  has  continued  to  date,  with  most  of  the  development  in 
1911  and  1912.  Wells  were  reported  ^ith  an  initial  production  as 
high  as  400  barrels.  The  thstrict  has  shown  great  lasting  qualities. 
Within  the  last  two  years  vacuum  has  been  generally  applied. 
There  is  considerable  water  trouble  in  some  parts  of  the  district. 

Glenn  Pool,  Creek  County,  Okla. 

The  curves  and  tables  for  the  Glenn  field  cover  townships  16-19 
north,  ranges  11-13  east.  This  includes  the  Glenn,  Sapulpa,  and 
Taneha  pools,  with  the  northeast  and  southeast  extensions. 
Several  sands  are  productive  in  this  area,  the  more  important  of 

which  are  the  Red  Fork  Glenn,  and  Squaw  or  Taneha.  Some 
production  has  also  been  obtained  from  sands  above  the  Red  Fork, 
one  between  the  Red  Fork  and  Glenn,  and  three  below  the  Taneha 
sand.  Of  the  three  important  producing  sands,  the  Red  Fork  is 
about  1,100  feet  deep  and  ranges  from  10  to  30  feet  in  tliickness. 


ESTIMATED  FUTURE  PRODUCTION  TABLE- 
DISTRICT. 


-GLENN  POOL 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Average 
Production 

per  WeU 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

150 

390 

3,500 

8,000 

38,500 

56.300 

200 

510 

7,000 

14,500 

42,500 

60.000 

300 

840 

10,500 

20,200 

45,500 

63.600 

400 

1,100 

14,000 

25.600 

49,000 

67,000 

500 

1,350 

i      17,500 

30.700 

52,500 

70.150 

600 

1,600 

20,000 

34,300 

56,000 

73,200 

700 

1,S00 

!     21,000 

35,000 

'      59.500 

76.150 

1,050 

2,650 

24,500 

40.200 

63,000 

79.150 

1,750 

4,200 

28,000 

44,300 

66,500 

82.000 

2,800 

6,700 

!     31,500 

48,500 

70,000 

84.600 

3,150 

7,250 

35,000 

52,600 

81,500 

92,400 

Average    Production    p^r    ivell     during     Ta^xible.       Year      in     Barre/i 

FIG.  8— ESTIMATED  AVERAGE   FUTURE   PRODUCTION  CURVES,    PART   OF    MIDCONTINENT   FIELD. 


(To  fnco  page  128.) 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 


129 


The  Glenn  sand  averages  about  90  feet  in  thickness  and  about 
1,750  feet  below  the  surface.  The  Squaw  or  Taneha  sand  is  about 
30  feet  thick,  and  is  found  at  a  depth  of  about  1,900  feet.  Of 
these,  the  Glenn  is  the  most  important,  and  the  Red  Fork  is  second 
as  a  protlucer.  Discovery  here  was  in  1906.  The  structure  is 
monoclinical  with  a  westward  dip  of  about  50  feet  per  mile.  Cross 
flexures  and  terraces  on  this  westward  dip  seem  to  have  had  a 
definite  influence  on  oil  accumulation.  The  average  spacing  is 
about  6  acres  per  well. 

Gushing  Field,  Creek  County,  Okla. 

The  curves  and  tables  for  the  Gushing  field  cover  townships 
16,  17,  18,  and  19  north,  ranges  6  and  7  east.  This  includes  Gush- 
ing proper  and  outlying  pools.  Discovery  was  made  in  1912  in 
the  Wheeler  sand,  production  being  developed  later  in  the  Lay  ton, 
Bartlesville,  and  Tucker  sands.  Of  the  four  important  sands,  the 
Layton  is  from  1,200  to  1,500  feet  deep,  and  has  an  average  thick- 
ness of  about  50  feet.  The  Wheeler  sand  averages  about  2,000  to 
2,100  feet  in  depth  and  about  50  feet  in  thickness.  The  Bartles- 
ville sand  is  from  2,500  to  2,700  feet  deep  and  ranges  in  thickness 
from  50  to  200  feet.     The  Tucker  sand  is  about  2,800  feet  deep  and 


ESTIMATED  FUTURE  PRODUCTION  TABLE- 
DISTRICT. 


-GUSHING 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Ta.xable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Ta.xable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Barrels. 

500 
1,000 
1,500 
2,000 
2,500 
3,000 
3,500 
4,000 
4,500 
5,000 
6,000 

Barrels. 

400 
1,000 
1,600 
2,1.50 
2,800 
3,260 
3,800 
4,370 
5,000 
5,700 
6,800 

Barrels. 

7,000 
8,000 
9,000 
10,000 
12,000 
14,000 
16,000 
18,000 
20,000 
25,000 
30,000 

Barrels. 

7,900 
9,000 
10,100 
11,200 
13,400 
15,600 
17,800 
19,800 
22,000 
27,000 
32,000 

Barrels. 

35,000 
40,000 
45,000 
50,000 
55,000 
60,000 
65,000 
70,000 
75,000 
80,000 

Barrels. 

37,000 
41.700 
45,900 
49,900 
53,600 
57,200 
60,600 
64,100 
67,400 
70,600 

MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 


129 


The  Glenn  sand  averages  about  90  feet  in  thickness  and  about 
1,750  feet  below  the  surface.  The  Squaw  or  Taneha  sand  is  about 
30  feet  thick,  and  is  found  at  a  depth  of  about  1,900  feet.  Of 
these,  the  Glenn  is  the  most  important,  and  the  Red  Fork  is  second 
as  a  producer.  Discovery  here  was  in  190G.  The  structure  is 
monoclinical  with  a  westward  dip  of  about  50  feet  per  mile.  Cross 
flexures  and  terraces  on  this  westward  dip  seem  to  have  had  a 
definite  influence  on  oil  accumulation.  The  average  spacing  is 
about  6  acres  per  well. 


Cushing  Field,  Creek  County,  Okla. 

The  curves  and  tables  for  the  Cushing  field  cover  townships 
16,  17,  18,  and  19  north,  ranges  6  and  7  east.  This  includes  Cush- 
ing proper  and  outlying  pools.  Discovery  was  made  in  1912  in 
the  Wheeler  sand,  production  being  developed  later  in  the  Lay  ton, 
Bartlesville,  and  Tucker  sands.  Of  the  four  important  sands,  the 
Layton  is  from  1,200  to  1,500  feet  deep,  and  has  an  average  thick- 
ness of  about  50  feet.  The  Wheeler  sand  averages  about  2,000  to 
2,100  feet  in  depth  and  about  50  feet  in  thickness.  The  Bartles- 
ville sand  is  from  2,500  to  2,700  feet  deep  and  ranges  in  thickness 
from  50  to  200  feet.     The  Tucker  sand  is  about  2,800  feet  deep  and 


ESTIMATED  FUTURE  PRODUCTION  TABLE- 
DISTRICT. 


-CUSHING 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

l?ecoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

500 

400 

7,000 

7,900 

35,000 

37,000 

1,000 

1,000 

8,000 

9,000 

40,000 

41.700 

1,500 

1,600 

9,000 

10,100 

45,000 

45,900 

2,000 

2,1.50 

10,000 

11,200 

50,000 

49,900 

2,500 

2,800 

12,000 

13,400 

55,000 

53,600 

3,000 

3,260 

11,000 

15,600 

60,000 

57,200 

3,500 

3,800 

16,000 

17,800 

()5,000 

60,600 

4,000 

4,370 

18,000 

19,800 

70,000 

64,100 

4,500 

5,000 

20,000 

22,000 

75,000 

67,400 

5,000 

5,700 

25,000 

27,000 

80,000 

70,600 

6,000 

6,800 

30,000 

32,000 

130 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 


is  about  25  feet  thick.  The  Layton  is  a  true  sand,  gives  fair-sized 
wells  that  held  up  fairly  well ;  the  Wheeler  is  a  sand  and  lime  forma- 
tion in  which  the  wells  have  large  initial  production  but  decline 
rapidly  and  have  short  lives;  the  Bartlesville  sand  is  a  true  sand 
and  has  many  pays.  It  is  by  far  the  most  important  of  the  four 
sands  and  gives  very  large  wells  but  has  developed  much  water 
trouble.  Because  of  the  four  sands,  there  are  often  several  wells 
drilled  on  each  location,  but  the  average  spacing  for  each  sand 
is  about  7  acres  per  well. 


Muskogee-Boynton  District,  Muskogee  County.  Okla. 

These  fields  were  combined  into  one  district,  since  the  individual 
lease  records  plotted  as  the  same  type  of  curve.  Wells  are  scat- 
tered and  fields  spotted.  Sands  are  variable  in  thickness  and 
character. 


ESTIMATED  FUTURE  PRODUCTION  TABLE— MUSKOGEE- 
BOYNTON  DISTRICT. 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

150 

150 

3,500 

4,700 

17,000 

18,250 

300 

300 

4,000 

5,400 

18,000 

19,100 

400 

500 

4,500 

6,000 

19,000 

19,900 

500 

650 

5,000 

6,500 

20,000 

20,700 

600 

800 

6,000 

7,700 

22,000 

22,200 

700 

900 

7,000 

8,800 

24,000 

23,600 

800 

1,100 

8,000 

9,850 

26,000 

25,200 

900 

1,200 

9,000 

10,800 

28,000 

26,800 

1,000 

1,400 

10,000 

11,900 

30,000 

27,400 

1,200 

1,700 

11,000 

12,900 

32,000 

28,500 

1,400 

1,950 

12,000 

13,800 

34,000 

29,450 

1,600 

2,250 

13,000 

14,750 

36,000 

30,350 

1,800 

2,500 

14,000 

15,650 

38,000 

31,200 

2,000 

2,750 

15,000 

16,500 

40,000 

32,000 

2,500 

3,400 

16,000 

17,400 

42,000 

32,800 

3,000 

4,100 

MANUAL   FOR  THE  OIL  AND   GAS  INDUSTRY 


131 


Okmulgee  Field,  Okmulgee  County,  Okla. 

The  curves  and  tables  for  the  Okmulgee  field  cover  townships 
12-15  north,  and  range  12-14  east.  This  includes  several  small  but 
distinct  areas  of  production.  Several  sands  are  productive  in  this 
large  area.  The  zone  of  production,  taking  the  field  as  a  whole,  is 
from  500  feet  to  nearly  2,500  feet  deep  and  the  sands  range  from 
2  feet  to  200  feet  thick,  but  average  less  than  100  feet.  As  the  sand 
lenses  are  notably  discontinuous,  detailed  treatment  of  the  curves 
of  the  separate  lenses  probably  would  not  be  justified.  Some 
leases,  however,  produce  oil  from  three  distinct  horizons.  The 
thicker  sands,  in  some  cases  at  least,  carry  salt  water  in  the  lower 
portions,  and  in  this  may  effect  future  recoveries.  In  one  well, 
production  may  range  from  500  feet  to  800  feet  in  depth.  More 
commonly  ones  and  furnishes  the  oil.  Since  the  sands  are  lentic- 
ular, the  area  is  not  uniformly  productive.  The  general  structure 
is  a  westward  dipping  monocline,  but  the  subsurface  structures 
are  not  well  indicated  at  the  surface.  Unconformable  strati- 
graphic  relations  seem  to  be  indicated,  but  textural  features  and 
the  character  of  the  cement  in  the  sands  may  be  important  factors. 
Discovery  of  oil  was  made  here  about  1907.  The  average  well 
spacing  is  about  8  to  10  acres. 


ESTIMATED   FUTURE   PRODUCTION   TABLE— OKMULGEE 
DISTRICT. 


Averane 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

150 

150 

1,500 

3,320 

5,000 

9,300 

200 

300 

2,000 

4,350 

5,500 

10,000 

250 

420 

2,500 

5,330 

6,000 

10,700 

300 

550 

3,000 

G,150 

6,500 

11,500 

350 

G75 

3,.500 

7,000 

7,000 

12,150 

400 

800 

4,000 

7,800 

7,500 

12,800 

500 

1,050 

4,500 

8,500 

8,000 

13,500 

1,000 

2,250 

132 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY 


Garher  Pool,  Garfield  County,  Okla. 

This  is  one  of  the  younger  pools  of  Oklahoma,  the  discovery- 
well  being  brought  in  late  in  1916.  Drilling  is  somewhat  difficult 
owing  to  the  red-beds  strata  which  overlie  the  production  sands. 
The  field  is  at  present  confined  to  the  limits  of  a  domal  structure 
found  in  townships  21  and  22  north  and  ranges  3  and  4  west 
One  oil  and  one  gas  sand  are  found,  the  gas  at  about  850  feet  and 
the  oil  at  approximately  1,100  feet. 


ESTIMATED  FUTURE  PRODUCTION  TABLE- 
DISTRICT. 


-GARBER 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Barrels. 
750 
1,000 
1,500 
2,000 
2,500 
3,000 
3,500 
4,000 
4,500 
5,000 

Barrels. 

0 
300 
1,000 
1,600 
2,200 
2,700 
3,300 
3,700 
4,200 
4,500 

Barrels. 

6,000 

7,000 

8,000 

9,000 

10,800 

12,500 

15,000 

17,500 

20,000 

22,500 

Barrels. 

5,400 

6,100 

6,800 

7,400 

7,900 

9,300 

10,300 

11,400 

12,500 

13,400 

Barrels 

25,000 
30.000 
35,000 
40,000 
45,000 
50,000 
60,000 
70,000 
80,000 

1 

Barrels. 

14,400 
16,300 
17,800 
19,100 
20,300 
21,600 
23,800 
25,800 
27,800 

Healdton  Field,  Carter  County,  Okla. 

The  curves  and  tables  for  the  Healdton  field  cover  townships 
3  and  4  south,  ranges  3  and  4  west.  Production  here  is  essentially 
from  two  horizons,  the  so-called  Healdton  sand,  at  depths  from  SCO 
to  1,200  feet,  and  the  deeper  sand  in  the  southeast  part  of  the  field 
between  1,800  and  2,000  feet,  which  may  or  may  not  be  the  same. 
One  well  has  production  from  the  Bull  Head  sand  at  a  depth  of 
about  2,800  feet.  The  Healdton  sand  consists  of  sand  lenses 
from  3  feet  to  more  than  60  feet  thick,  separated  by  beds  of  shale 
and  thin  limestone.  The  deeper  sands  in  the  southeast  extension 
have  the  same  characteristics.  Some  of  the  wells  are  producing 
from  the  upper  sand  lenses,  other  wells  are  producing  only  from  the 
lower  portion  of  the  Healdton  sand,  and  others  are  producing 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY 


133 


from  several  or  all  of  the  sand  lenses  penetrated  in  these  places. 
The  general  structure  is  that  of  a  dome  with  a  northwest  and  a 
southeast  extension,  with  an  alignment  parallel  to  the  Arbuckle 
Mountains.  The  steepest  dip  is  to  the  southwest  at  about  400 
feet  to  the  mile,  and  this  edge  of  production  is  remarkably  sharply 
outlined.  Subsurface  structures  do  not  correspond  closely  with 
those  at  the  surface,  and  their  interpretation  is  dependent 
upon  well  records.    Accumulation  seems  to  have  been  influenced 


ESTIMATED  FUTURE  PRODUCTION  TABLE- 
DISTRICT. 


-HEALDTON 


Average 
Production 

per  Well 

for  Ta.xable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Ta.xable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Vear. 

Estimated 

Recoverable 

Underground 

Reserves. 

Barrels. 

250 

500 

1,000 

2,000 

3,000 

4,000 

5,000 

10,000 

15,000 

Barrels. 

0 

700 

1,575 

3,300 

5,000 

6,850 

8,500 

16,200 

23,200 

Barrels. 
20,000 
25,000 
30,000 
35,000 
40,000 
45,000 
50,000 
55,000 
60,000 

Barrels. 

30,200 

37,700 
44,000 
52,000 
59,000 
66,000 
73,000 
80,000 
87,1.50 

Barrels. 

65,000 
70,000 
75,000 
80,000 
85,000 
90,000 
95,000 
100,000 

Barrels. 

94,300 
101,3.50 
108,200 
115,250 
122,500 
129,400 
136,.500 
143,500 

ESTIMATED  FUTURE  PRODUCTION  TABLE- 
DISTRICT,  OKLA. 


-BLACKWELL 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves. 

Barrels. 

500 

1,000 

2,500 

5,000 

7,500 

10,000 

12,.500 

15,000 

17,.500 

20,000 

Barrels. 

0 

1,000 

3,000 

6,500 

9,500 

12,000 

14,000 

16,000 

17,.500 

18,800 

Barrels. 

22,.500 
25,000 
30,000 
35,000 
40,000 
45,000 
50,000 
()0,000 
70,000 
80,000 

Barrels. 

20,000 
21,000 
23,200 
25,200 
26,800 
28,500 
29,800 
32,500 
34,700 
36,700 

Barrels. 

90,000 
100,000 
125,000 
150,000 
175,000 
200,000 
250,000 
300,000 
350,000 
400,000 

Barrels. 

38,400 
40,000 
44,100 
48,500 
.52,600 
56,800 
65,200 
63,800 
82,200 
90,700 

134  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

strongly  by  texture  as  well  as  by  structure.     The  first  production 
was  in  August,  1913. 

The  average  well  spacing  is  about  2|  acres. 

Corsicana  Pool,  Navarro  County,  Tex. 

The  Corsicana  pool  is  the  oldest  producing  field  in  the  State, 
being  now  in  its  twenty-third  year.  The  field  is  usually  divided 
into  two  districts,  the  Corsicana  or  light-oil  pool,  which  supphes  a 
crude  of  about  38°  Baume,  and  the  Powell,  or  heavy-oil  district, 
furnishing  oil  of  about  24°  Baume.  The  first  oil  was  produced  in 
1896.  The  Powell  pool  was  opened  in  1900.  As  production  in 
this  district  declines  water  encroaches  and  a  number  of  properties 
have  been  abandoned.  The  sands  which  produce  the  heavy  and 
light  oil  are  in  different  geological  horizons.  The  heavy-oil  sand 
probably  corresponds  to  the  Nacatoch  sand  of  the  Caddo  field, 
Louisiana.  The  light-oil  sands  occur  geologically  about  800  feet 
lower.  The  Corsicana  light-oil  sands  are  found  from  900  to  1,200 
feet  and  the  Powell  sands  are  found  from  650  to  950  feet  below  the 
surface.  They  range  in  thickness  from  a  few  feet  up  to  60  feet. 
A  comparison  of  the  various  properties  in  the  heavy  and  light  oil 
pools  seemed  to  indicate  that  the  rate  of  decline  was  approximately 


ESTIMATED  FUTURE  PRODUCTION  TABLE- 
FIELD. 


-CORSICANA 


Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Average 
Production 

per  Well 

for  Taxable 

Year. 

Estimated 

Recoverable 

Underground 

Reserves 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

100 

0 

2,400 

15,700 

4,600 

27,800 

200 

800 

2,600 

16,800 

4,800 

28,900 

400 

2,500 

2,800 

17,900 

5,000 

30,000 

600 

4,100 

3,000 

19,000 

5,200 

31,200 

800 

5,500 

3,200 

20,100 

5,400 

32,300 

1,000 

7,000 

3,400 

21,300 

5,500 

32,800 

1,200 

8,300 

3,600 

22,400 

6,000 

35,600 

1,400 

9,600 

3,800 

23,400 

6,500 

38,300 

1,600 

10,750 

4,000 

24,. 500 

7,000 

41,100 

1,800 

12,200 

4,200 

25,600 

7,500 

43,800 

2,000 

13,400 

4,400 

26,700 

8,000 

46,600 

2,200 

14,500 

i 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 


135 


the  same  in  both  instances.  It  was  thought  advisable,  therefore, 
to  consider  the  district  as  one  pool,  and  the  curve  will  apply  to 
all  the  properties  in  tliis  field. 


Electra  Pool,  Wichita  County,  Tex. 

The  Electra  pool  is  located  in  the  western  portion  of  Wichita 
and  the  eastern  portion  of  Wilbarger  Counties.  The  pool  was 
opened  in  1910  and  at  the  present  time  its  general  limits  seem  fairly- 
well  defined.  The  main  pool  includes  about  9,800  acres  of  proven 
territory.  The  oil  is  found  in  overlapping  sands  at  varying  depths 
between  350  and  2,050  feet  below  the  surface.  No  individual  sand 
has  any  great  lateral  extent,  though  the  sands  overlap  in  such  man- 
ner that  production  is  continuous  over  the  entire  area,  with  no 
intervening  dry  spots  of  any  considerable  size.  Individual  sands 
are  seldom  more  than  25  feet  thick,  though  in  a  few  instances  35 
feet  or  more  have  been  reported.  The  average  thickness  of  sands 
in  the  field  will  probably  be  well  under  25  feet.  The  oil  produced 
in  this  district  has  a  gravity  of  from  40°  to  44°  Baume.  The  gas 
pressure  has  never  been  strong  in  wells,  even  in  the  early  stages 
of  development. 

ESTIMATED    FUTURE   PRODUCTION    TABLE— ELECTRA 

FIELD. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
of  Well. 

Average 
Prodtiction 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
of  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Futuie 

Production 
of  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Parrels. 

100 

0 

2,800 

7,500 

7,200 

18,600 

200 

400 

3,000 

8,000 

7,600 

19,500 

400 

900 

3,200 

8,600 

8,000 

20,400 

600 

1,600 

3,400 

9,100 

8,400 

21,300 

800 

2,100 

3,()00 

9,600 

8,800 

22,200 

1,000 

2,600 

3,800 

10,200 

9,200 

23,000 

1,200 

3,200 

4,000 

10,700 

9,600 

23,800 

1,400 

3,700 

4,400 

11,700 

10,000 

24,600 

1,600 

4,300 

4,800 

12,700 

11,000 

26,600 

1,800 

4,700 

5,200 

13,700 

12,000 

28,500 

2,000 

5,300 

5,600 

14,700 

13,000 

30,400 

2,200 

5,S00 

6,000 

15,700 

14,000 

32,200 

2,400 

6,400 

6,400 

16,700 

15,000 

33,900 

2,600 

7,000 

6,S()0 

17,700 

16,000 

35,600 

136 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 


Burkhurnett  Pool,  Wichita  County,  Tex. 

The  Burkburnott  jjool  has  an  east-west  axis  and  includes 
approximately  10,500  acres  of  proven  territory.  The  sands  are 
fairly  regular  but  it  is  often  hard  and  unproductive  in  spots  and 
relatively  open  and  prolific  near  by.  The  bulk  of  production 
conies  from  sands  found  between  1,000  and  1,800  feet  below  the 
surface,  with  a  range  in  thickness  up  to  35  feet.  In  some  places 
a  small  production  is  secured  from  shallow  sands  found  between 
350  and  500  feet.     The  oil  has  a  gravity  of  40°  to  42°  Baume. 


ESTIMATED  FUTURE  PRODUCTION  TABLE- 
FIELD. 


-BURKBURNETT 


Average 
Production 

of  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
of  Well. 

Average 
Production 

of  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
of  Well. 

Average 
Production 

of  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
of  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

300 

0 

3,600 

12,300 

10,000 

34,000 

400 

600 

3,800 

13,000 

11,000 

37,100 

600 

1,300 

4,000 

13,700 

12,000 

40,200 

800 

2,100 

4,400 

15,000 

13,000 

43,500 

1,000 

2,800 

4,800 

16,500 

14,000 

46,500 

1,200 

3,500 

5,200 

17,800 

15,000 

49,600 

1,400 

4,300 

5,600 

19,300 

16,000 

52,600 

1,600 

5,000 

6,000 

20,600 

17,000 

55,700 

1,800 

5,700 

6,400 

22,000 

18,000 

58,600 

2,000 

6,500 

6,800 

23,300 

19,000 

61,600 

2,200 

7,200 

7,200 

24,800 

20,000 

64,500 

2,400 

8,000 

7,600 

26,000 

22,000 

70,300 

2,600 

8,700 

8,000 

27,400 

24,000 

76,000 

2,800 

9,400 

8,400 

28,700 

26,000 

81,800 

3,000 

10,100 

8,800 

30,000 

28,000 

88,500 

3,200 

10,800 

9,200 

31,300 

30,000 

93,000 

3,400 

11,500 

9,600 

32,800 

32,000 

98,500 

FUTURE  PRODUCTION  CURVES  FOR  NORTHERN  LOUISIANA 

FIELDS. 

The  oil  fields  covered  by  this  investigation  are  those  in  the 
northern  part  of  the  State  of  Louisiana  generally  known  as  the 
Caddo,  the  De  Soto  and  the  Red  River  pools.  There  are  other 
very  small  producing  areas  in  the  district,  but  they  have  not  suf- 
ficient production  to  furnish  data  on  which  to  construct  curves. 


MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY  137 

The  production  area  in  Marion  County,  Tex.,  is  also  included 
in  this  report,  as  it  is  merely  an  extension  of  the  Caddo  oil  field. 

Fairly  complete  data  were  procured  on  about  85  per  cent  of  the 
properties  in  the  producing  area  and  the  curves  show  the  average 
production  per  well. 

The  general  geological  conditions  in  these  fields  are  similar. 
The  pay  sands  occur  in  very  gentle  folds  and  the  oil  is  at  first  under 
high  gas  pressure,  and  is  in  close  association  with  bottom  water 
over  nearly  all  the  field.  This  water  is  an  ever-present  menace  and 
necessitates  great  care  in  drilling  as  well  as  in  subsequent  opera- 
tions. Wells  with  large  production  often  go  suddenly  to  water  and 
even  with  care  this  is  the  invariable  end  of  all  wells  in  these  fields. 

Surface  exposures  are  so  irregular  and  the  formations  exposed  so 
recent  that  they  give  no  clue  to  underground  structure. 

The  main  source  of  the  oil  is  the  "  Woodbine  "  sand  of  Creta- 
ceous age,  which  is  encountered  at  a  depth  of  from  2,200  to  2,300 
feet.  Because  of  the  poor  samples  obtained  by  the  rotary  method 
of  drilling,  which  is  universally  used  here,  the  well  logs  generally  • 
show  oil  as  coming  from  shale.  As  it  is  always  the  intent  of  the 
driller  to  merely  touch  the  top  of  the  oil  sand,  because  of  the 
danger  of  water,  the  thickness  of  this  "  sand  "  is  not  definitely 
known. 

The  Nacatoch  sand  at  a  depth  of  about  800  feet  produces  a 
great  deal  of  gas  and  some  heavy  oil.  The  production  from  this 
sand  is  of  minor  importance  compared  to  the  production  from  the 
Woodbine,  and  the  records  are  such  that  it  is  impossible  to  segre- 
gate its  production. 

The  Caddo  Oil  Field. 

For  the  purpose  of  estimating  future  production,  this  field  is 
divided  into  four  pools.  These  divisions  were  made  on  a  basis  of 
decline  of  production  by  comparing  decline  curves  over  the  various 
areas.  Areas  where  the  decline  curves  were  similar  were  taken  to 
represent  a  distinct  pool  and  a  general  curve  for  this  was  con- 
structed. 

The  Mooringsport  pool  comprises  townships  21  north,  range  16 
west,  20  north,  range  16  west,  and  20  north,  range  15  west.  A 
curve  was  constructed  for  each  of  these  townships,  and  other 
curves  for  each  of  the  larger  companies  whose  holdings  are  scat- 
tered through  these  townships.     These  curves  proved  practically 


138  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

identical  after  the  period  of  great  gushers  was  past,  so  all  were 
combined  into  one  general  curve. 

A  separate  curve  was  made  for  Marion  County,  Tex.,  not 
because  it  is  materially  different,  but  to  have  a  special  record  from 
another  State. 

The  Vivian  oil  field,  to  the  east  and  south  of  Vivian,  township 
16  north,  range  22  west,  township  15  north,  range  22  west,  forms 
another  distinct  unit  for  which  a  curve  was  constructed. 

The  Pine  Island  pool,  township  21  north,  range  15  west,  shows 
a  very  high  flush  production  and  rapid  decline.  The  oil  is  of  low 
gravity,  27°  Baume,  and  comes  from  the  Woodbine  sand  under  high 
gas  pressure.  No  accurate  estimate  of  future  production  can  be 
made  on  the  average  production  of  a  well  during  one  year,  because 
the  field  is  so  new  that  the  records  extend  back  only  15  months 
and  the  decline  is  so  rapid  that  wells  giving  as  high  as  600  barrels  a 
day  are  exhausted  within  a  year.  For  this  field  a  curve  was  made 
from  which  the  future  production  can  be  estimated,  if  the  pro- 
duction for  a  month  is  known.  To  determine  the  estimated  reserve 
per  well,  apply  the  production  for  the  last  month  of  the  taxable 
year  to  the  curve  and  read  off  the  estimated  future  production. 

In  parts  of  the  Caddo  field  large  areas  contain  very  few  dry 
holes  and  undrilled  ground  bounded  on  four  sides  by  production 
can  reasonably  be  assumed  to  be  proven  territory. 

The  Be  Soto  and  Red  River  Fields. 

The  De  Soto  oil  field  is  located  in  De  Soto  Parish,  La.,  in  the 
southeastern  part  of  township  13  north,  range  12  west,  and  the 
northeastern  part  of  township  12  north,  range  13  west,  and  extends 
a  little  into  the  township  to  the  west. 

The  Red  River  oil  field  is  located  in  Red  River  Parish,  town- 
ship 13  north,  range  10  west,  and  township  13  north,  range  11 
west.  Production  is  ''  spotted  "  and  dry  holes  are  frequent  near 
large  producing  wells;  in  the  Red  River  district  the  sands  are 
slightly  more  uniformly  productive,  but  the  decline  is  more  rapid 
than  in  the  De  Soto  field.  No  undrilled  ground  can  reasonably 
be  called  proven  here. 

The  producing  sand  here  is  probal)ly  the  same  as  the  Woodbine 
in  the  Caddo  field  and  occurs  at  a  depth  of  2,100  to  2,300  feet. 
The  gravity  of  the  oil  varies  from  38°  Baume  to  45.7° 


te 

::: 

-  _ 

n 

r 

f  - 

T 

f 

I 

L 
1-. 

1 



III 

f 

.-4 

::; 

■icfuci 


IMATEC 
■Pine  Isia 


Average    Production  per   well    during    Ta?<abfe^    Year,  in    Barre/s. 


IIIOGO" — 19. 


FIG.  9,— ESTIMATED  , 
Note.— Pino  Islan. 


yERACE    FUTURE   PRODUCTION   CURVES,   NORTHWESTERN    LOUISIANA. 
curve  Is  for  last  month's  production  instead  of  annual  production.     Seo  text. 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY 


139 


ESTIMATED  FUTURE  PRODUCTION  TABLE. 

MOORINGSPORT   PoOL,    CaDDO   PaRISH,    La. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

700 

0 

3,250 

5,800 

12,500 

25,300 

1,000 

900 

3,500 

G,200 

15,000 

30,300 

1,250 

1,200 

3,750 

7,000 

17,500 

35,400 

1,500 

2,000 

4,000 

7,500 

20,000 

40,300 

1,750 

2,500 

4,250 

8,000 

22,500 

45,200 

2,000 

3,100 

4,500 

8,600 

25,000 

50,000 

2,250 

3,300 

4,750 

9,200 

30,000 

58,500 

2,500 

4,100 

5,000 

9,700 

35,000 

65,500 

2,750 

4,800 

7,500 

15,000 

40,000 

71,200 

3,000 

5,200 

10,000 

20,200 

Marion  County,  Tex. 


1,000 

700 

4,500 

6,600 

9,500 

14,600 

1,250 

1,200 

5,000 

7,400 

10,000 

15,300 

1,500 

1,500 

5,500 

8,300 

12,250 

19,300 

1,750 

1,900 

6,000 

9,000 

15,000 

23,200 

2,000 

2,400 

6,500 

9,800 

17,250 

27,000 

2,250 

2,800 

7,000 

10,600 

20,000 

30,400 

2,500 

3,300 

7,500 

11,400 

25,000 

36,500 

3,000 

4,100 

8,000 

12,200 

30,000 

41,600 

3,500 

4,900 

8,500 

13,000 

35,000 

46,300 

4,000 

5,800 

9,000 

13,800 

40,000 

50,500 

Vivian  Pool,  Caddo  Parish,  La. 


750 

0 

3,500 

3,800 

8,000 

9,300 

1,000 

400 

4,000 

4,400 

9,000 

10,400 

1,250 

800 

4,500 

5,100 

10,000 

11,500 

1,500 

1,100 

5,000 

5,700 

15,000 

16,700 

1,750 

1,400 

5,500 

6,300 

20,000 

12,()00 

2,000 

1,750 

6,000 

7,000 

25,000 

2t),400 

2,250 

2,100 

6,500 

7,500 

30,000 

31,000 

2,500 

2,400 

7,000 

8,200 

33,000 

35,500 

3,000 

3,100 

7,500 

8,750 

40,000 

40,000 

MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY 


139 


ESTIMATED  FUTURE  PRODUCTION  TABLE. 

MOORINGSPORT  PoOL,   CaDDO   ParISH,   La. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 
per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

700 

0 

3,250 

5,800 

12,500 

25,300 

1,000 

900 

3,500 

6,200 

15,000 

30,300 

1,250 

1,200 

3,750 

7,000 

17,500 

35,400 

1,500 

2,000 

4,000 

7,500 

20,000 

40,300 

1,750 

2,500 

4,250 

8,000 

22,500 

45,200 

2,000 

3,100 

4,500 

8,600 

25,000 

50,000 

2,250 

3,300 

4,750 

9,200 

30,000 

58,500 

2,500 

4,100 

5,000 

9,700 

35,000 

65,500 

2,750 

4,800 

7,500 

15,000 

40,000 

71,200 

3,000 

5,200 

10,000 

20,200 

Marion  County,  Te^^. 


1,000 

700 

4,500 

6,600 

9,500 

14,600 

1,250 

1,200 

5,000 

7,400 

10,000 

15,300 

1,500 

1,500 

5,500 

8,300 

12,250 

19,300 

1,750 

1,900 

6,000 

9,000 

15,000 

23,200 

2,000 

2,400 

6,500 

9,800 

17,250 

27,000 

2,250 

2,800 

7,000 

10,600 

20,000 

30,400 

2,500 

3,300 

7,500 

11,400 

25,000 

36,500 

3,000 

4,100 

8,000 

12,200 

30,000 

41,600 

3,500 

4,900 

8,500 

13,000 

35,000 

46,300 

4,000 

5,800 

9,000 

13,800 

40,000 

50,500 

Vivian  Pool,  Caddo  Parish,  La. 


750 

0 

3,500 

3,800 

8,000 

9,300 

1,000 

400 

4,000 

4,^00 

9,000 

10,400 

1,250 

800 

4,500 

5,100 

10,000 

11.500 

1,500 

1,100 

5,000 

5,700 

15,000 

16,700 

1,750 

1,400 

5,500 

6,300 

20,000 

12,600 

2,000 

1,750 

6,000 

7,000 

25,000 

26,400 

2,250 

2,100 

6,500 

7,500 

30,000 

31,000 

2,500 

2,400 

7,000 

8,200 

35,000 

35,500 

3,000 

3,100 

7,500 

8,750 

40,000 

40,000 

140 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY 


ESTIMATED  FUTURE  PRODUCTION  TABLE— Continued. 


Pine  Island  Pool, 

Caddo  Parish,  La.* 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

100 

0 

5,000 

13,600 

20,000 

37,300 

500 

1,100 

7,500 

18,600 

22,500 

40,500 

1,000 

3,000 

10,000 

23,000 

25,000 

43,400 

2,000 

6,300 

12,500 

27,000 

27,500 

46,400 

3,000 

9,000 

15,000 

30,700 

30,000 

49,300 

4,000 

11,500 

17,500 

34,000 

De  Soto  Field,  De  Soto  Parish,  La. 


700 

0 

4,500 

5,800 

15,000 

17,300 

1,000 

700 

5,000 

6,400 

17,500 

19,800 

1,500 

1,500 

6,000 

7,500 

20,000 

22,000 

2,000 

2,400 

7,000 

8,700 

22,500 

24,200 

2,500 

3,000 

8,000 

9,800 

25,000 

26,500 

3,000 

3,800 

9,000 

11,100 

30,000 

31,200 

3,500 

4,500 

10,000 

12,200 

35,000 

38,200 

4,000 

5,100 

12,500 

14,700 

40,000 

40,500 

Red  River  Field,  Red  River  Parish,  La. 


900 

0 

10,000 

8,100 

27,500 

18,400 

1,000 

200 

12,500 

9,800 

30,000 

19,800 

2,250 

350 

15,000 

11,300 

32,500 

21,100 

1,500 

750 

17,500 

12,800 

35,000 

22,300 

2,500 

3,200 

20,000 

14,250 

37,500 

23,700 

5,000 

4,000 

22,500 

15,800 

40,000 

24,900 

7,500 

6,100 

25,000 

17,100 

*  Average  production  per  well  in  Pine  Island  table  is  for  last  month  of 
taxable  year.     See  text,  p.  138. 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY  141 

FUTURE  PRODUCTION  CURVES  FOR  THE  ROCKY  MOUNTAIN 

FIELDS. 

The  region  covered  in  this  investigation  comprises  the  Rocky- 
Mountain  district,  of  which  Wyoming,  Colorado,  and  Montana, 
given  in  the  order  of  their  importance,  constitute  the  most  valuable 
part  from  an  oil-producing  standpoint.  Furthermore,  of  these 
three  States,  Wyoming  is  by  far  the  most  important,  producing 
over  90  per  cent  of  the  oil. 

The  method  of  attack  consisted  of  the  collection,  study,  classi- 
fication, and  reduction  to  estimated  reserve  curves  of  all  average 
production  data  from  the  various  oil  fields  throughout  the  territory 
under  consideration. 

The  geologic  range  of  oil-bearing  formations  in  the  Rocky 
Mountain  region  extends  from  the  middle  of  the  upper  Cretaceous 
down  to  the  base  of  the  Pennsylvanian,  or  the  top  of  the  ]\Iadison 
or  Mississippi  Imiestone.  The  rocks  comprising  these  formations 
consist  mainly  of  sandstones  and  shales  with  a  very  small  percent- 
age of  limestone.  Throughout  the  stratigraphic  range  given  above 
oil-bearing  sandstones  occur  at  many  different  horizons,  but  the 
most  prolific  is  the  Frontier  sandstone  series,  or  Wall  Creek  sand- 
stones of  the  Colorado  formation.  The  prevailing  type  of  geologic 
structure  is  an  elongated  asymmetric  anticline  of  more  or  less  reg- 
ular outhne  with  dips  ranging  from  10  to  60  or  more  degrees,  the 
steeper  dips  generally  occurring  on  the  mountainward  side. 

The  producing  oil  fields  in  Wyoming  occur  around  the  outer 
margins  of  the  larger  structural  basins,  such  as  Powder  River 
Basin  lying  between  the  Big  Horn  Mountains  and  the  Black  Hills, 
the  Big  Horn  Basin  inclosed  by  the  Big  Horn,  Owl  Creek,  and 
Shoshone  Mountains,  the  Wind  River  Basin  bounded  by  the  Owl 
Creek,  Wind  River,  and  Sweet  Grass  Mountains,  and  the  Laramie- 
Rawlins  Basin  bordered  by  the  Laramie,  Medicine  Bow,  and  Raw- 
lins uplifts. 

The  fields  of  economic  importance  occurring  within  these  larger 
structural  basins  are  Salt  Creek,  Saddle  Rock,  Big  ]\luddy,  and 
Buck  Creek  in  the  Powder  River  Basin;  Grass  Creek,  Elk  Basin, 
and  Warm  Springs  in  the  Big  Horn  Basin;  Pilot  Butte  and  Hud- 
son in  the  Wind  Kiver  Basin;  and  Rock  Creek,  Lost  Soldier,  and 
Ferris  in  the  Laramie-Rawlins  Basin.  In  additioato  these,  several 
smaller  pools  are  found;  also  some  new  localities  which  may  prove 


142  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

ultimately  of  commercial  value.  In  Colorado  the  two  fields  are 
Florence,  located  in  the  Arkansas  embayment,  a  large  structural 
province,  occurring  in  the  front  range  of  the  Rocky  Mountains 
along  the  Arkansas  River  Valley,  and  the  Boulder  oil  field,  now 
practically  abandoned,  which  is  situated  at  the  base  of  the  Rocky 
Mountain  uplift  in  north  central  Colorado.  The  Florence  and 
Boulder  fields  are  nearly  exhausted  at  the  present  time. 

In  the  Rocky  Mountain  region  there  were  only  four  fields  where 
sufficient  data  were  available  to  construct  average  decline  curves 
on  which  to  base  estimates  of  reserves.  In  some  localities  the 
records  were  too  incomplete  to  obtain  the  necessary  production 
data  for  deriving  decline  curves,  while  other  promising  fields 
recently  discovered  were  too  new  to  afford  the  required  information 
for  estimating  their  reserves. 

With  the  exception  of  Florence,  the  time  during  which  the  fields 
have  been  producing  is  comparatively  short,  none  of  the  wells  hav- 
ing reached  the  point  of  exhaustion.  Indirectly  there  are  a  num- 
ber of  other  factors  which  vary  in  the  different  fields,  such  as 
character  of  structure,  well  spacing,  gravity  of  oil,  thickness  and 
porosity  of  sand,  etc.,  which  should  be  taken  into  account,  as  they 
more  or  less  influence  the  resulting  curve  of  the  field.  Under 
separate  headings  a  brief  description  is  given  of  the  essential  con- 
ditions as  found  in  each  field. 

The  Florence  oil  field  is  the  only  field  in  the  Rocky  Mountain 
district  now  producing  where  the  wells  have  in  part  reached  a  point 
below  the  economic  minimum  of  production  and  been  abandoned. 
The  first  well  was  drilled  here  in  1876,  and  while  the  production 
from  this  locality  was  never  large  the  life  of  the  wells  and  low 
operating  expense  have  permitted  its  continuous  operation  much 
beyond  the  time  that  would  ordinarily  be  expected.  Several 
hundred  wells  have  been  abandoned  in  this  region.  The  structure 
of  the  field  is  monoclinal  with  dips  in  the  productive  area  of  3°  to 
6°.  There  is  no  oil-bearing  sandstone  and  the  oil  does  not  follow 
any  definite  horizon  or  series  of  beds.  It  is  found  in  joints,  fissures, 
and  along  major  and  minor  fault  planes.  The  oil  has  a  gravity  of 
30.7°  Baume,  and  as  this  is  a  crevice  field  with  the  oil  segregated 
into  faulted  zones  any  general  systematic  spacing  of  wells  over  the 
entire  field  is  prevented.  Along  these  faulted  lines  wells  are 
placed  about  600  feet  apart. 

Four  types  of  decline  curves  were  found  to  exist  in  the  Florence 


™ 

■ 

^ 

-- 

--■ 

-- 

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'" 

1" 

'' 

■ 

'" 

[ 

r 

' 

-- 

IP' 

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i 

'' 

r 

r 

. 

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-- 

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:^  = 

-- 

^  — 

- — ' 

'-'-: 

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riMA 


tS^OOO  f^SOO  _ai\O0O  Zl^OO  2S,0O0  Z7,SOff  "  JCiOOO 

Average"    Production    per     tve//   cfurin^    Taxabfe^    Yean,  in    Barrefs. 

FIG.  10.— ESTIMATED  AVERAGE   FUTURE   PRODUCTION  CURVES,    ROCKY  MOUNTAIN    FIELD. 


(To  face  page  143.) 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY  143 

field.  These  types  did  not  appear  to  confine  themselves  to  any 
particular  part  of  the  field,  nor  did  the  types  seem  to  be  a  function 
of  the  depth.  From  this  it  would  appear  that  these  types  may 
possibly  be  related  to  the  size  and  extent  of  the  crevice  or  fissure 
penetrated  by  the  well.  It  has,  therefore,  been  impossible  to  give 
an  average  future  production  curve  for  the  Florence  field. 

Operating  methods  employed  in  the  Big  Muddy  field  to  date, 
together  with  the  short  period  of  its  production,  prevented  the 
construction  of  a  generalized  decline  curve  for  this  field.  The 
shallow  and  deep  production  has  been  run  into  the  same  receiving 
tanks.  Well  records  are  often  incomplete  and  the  first  oil  was  piped 
from  the  field  as  late  as  June,  1917,  the  first  wells  having  been 
drilled  in  1916.  The  oil  is  34°  gravity  Baume  and  well  spacing 
varies  from  4|  to  6|  acres  per  well.  The  first  and  second  pro- 
ductive sands  locally  designated  as  Shannon  are  reached  at  244 
to  415  and  985  to  1,100  feet,  respectively.  The  first  Wall  Creek 
occurs  at  a  depth  of  2,135  to  3,325  feet.  The  sands  are  similar  in 
physical  character  to  those  in  the  Salt  Creek  field. 


Salt  Creek  Field,  Natrona  county,  Wyo. 

This  is  the  most  important  field  in  the  Rocky  Mountain  region, 
and  the  curve  obtained  checks  out  very  well  with  the  actual  field 
results  to  date.  The  Salt  Creek  field  proper  is  an  elongated  dome 
of  the  asymmetric  type.  The  structiu'e  narrows  and  plunges 
slightly  to  the  north  and  widens  and  flattens  to  the  southeast.  In 
this  field  the  gravity  of  the  oil  is  37°  Baume,  and  the  well  spacing 
is  4.4  acres  per  well.  The  depth  to  the  top  of  the  first  Wall  Creek 
sandstone  varies  from  950  to  3,000  feet,  depending  on  the  posi- 
tion of  the  well  on  the  structure.  From  the  well  records  this  sand- 
stone appears  to  be  125  feet  thick.  The  interval  from  the  base  of 
this  structure  to  the  top  of  the  Dakota  is  about  1,300  feet,  and  in 
this  stratigraphic  range  there  are  six  distinct  lower  sandstone 
horizons  which  vary  from  10  to  65  feet  in  thickness,  only  one  of 
which,  the  first  Wall  Creek,  has  Ijeen  proven  productive  thus  far. 
The  physical  character  of  the  sands  in  Salt  Creek  is  very  favorable 
and  no  water-bearing  horizons  are  encountei-ed  above  the 
oil;  therefore,  operating  conditions  may  be  regarded  as  favor- 
able. 


I 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY  143 

field.  These  types  did  not  appear  to  confine  themselves  to  any- 
particular  part  of  the  field,  nor  did  the  types  seem  to  be  a  function 
of  the  depth.  From  this  it  would  appear  that  these  types  may 
possibly  be  related  to  the  size  and  extent  of  the  crevice  or  fissure 
penetrated  by  the  well.  It  has,  therefore,  been  impossible  to  give 
an  average  future  production  curve  for  the  Florence  field. 

Operating  methods  employed  in  the  Big  Muddy  field  to  date, 
together  with  the  short  period  of  its  production,  prevented  the 
construction  of  a  generalized  decline  curve  for  this  field.  The 
shallow  and  deep  production  has  been  run  into  the  same  receiving 
tanks.  Well  records  are  often  incomplete  and  the  first  oil  was  piped 
from  the  field  as  late  as  June,  1917,  the  first  wells  having  been 
drilled  in  1916.  The  oil  is  34°  gravity  Baume  and  well  spacing 
varies  from  4h  to  6^  acres  per  well.  The  first  and  second  pro- 
ductive sands  locally  designated  as  Shannon  are  reached  at  244 
to  415  and  985  to  1,100  feet,  respectively.  The  first  Wall  Creek 
occurs  at  a  depth  of  2,135  to  3,325  feet.  The  sands  are  similar  in 
physical  character  to  those  in  the  Salt  Creek  field. 


Salt  Creek  Field,  Natrona  county,  Wyo. 

This  is  the  most  important  field  in  the  Rocky  Mountain  region, 
and  the  curve  obtained  checks  out  very  well  with  the  actual  field 
results  to  date.  The  Salt  Creek  field  proper  is  an  elongated  dome 
of  the  asjanmetric  type.  The  structure  narrows  and  plunges 
slightly  to  the  north  and  widens  and  flattens  to  the  southeast.  In 
this  field  the  gravity  of  the  oil  is  37°  Baume,  and  the  well  spacing 
is  4.4  acres  per  well.  The  depth  to  the  top  of  the  first  Wall  Creek 
sandstone  varies  from  950  to  3,000  feet,  depending  on  the  posi- 
tion of  the  well  on  the  structure.  From  the  well  records  this  sand- 
stone appears  to  be  125  feet  thick.  The  interval  from  the  base  of 
this  structure  to  the  top  of  the  Dakota  is  about  1,300  feet,  and  in 
this  stratigraphic  range  there  are  six  distinct  lower  sandstone 
horizons  which  vary  from  10  to  65  feet  in  thickness,  only  one  of 
which,  the  first  Wall  Creek,  has  been  proven  productive  thus  far. 
The  physical  character  of  the  sands  in  Salt  Creek  ia  very  favorable 
and  no  water-bearing  horizons  are  encountered  above  the 
oil;  therefore,  operating  conditions  may  be  regarded  as  favor- 
able. 


144 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTBY 


ESTIMATED  FUTURE  PRODUCTION  TABLE— SALT  CREEK 
FIELD,  FIRST  WALL  CREEK  SAND. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

1,000 

0 

55,000 

184,000 

110,000 

289,000 

5,000 

30,000 

60,000 

195,000 

115,000 

297,000 

10,000 

54,000 

65,000 

205,000 

120,000 

305,000 

15,000 

74,000 

70,000 

215,000 

125,000 

313,000 

20,000 

91,000 

75,000 

225,000 

130,000 

321,000 

25,000 

107,000 

80,000 

234,000 

135,000 

329,000 

30,000 

122,000 

85,000 

244,000 

140,000 

337,000 

35,000 

136,000 

90,000 

253,000 

145,000 

344,000 

40,000 

148,000 

95,000 

262,000 

150,000 

351,000 

45,000 

160,000 

100,000 

271,000 

155,000 

358,000 

50,000 

172,000 

105,000 

280,000 

160,000 

365,000 

Grass  Creek  Field,  Hot  Springs  County,  Wyo. 

The  Frontier  formation  which  comprises  the  Wall  Creek  sand- 
stone is  not  exposed  on  this  structure,  but  erosion  has  progressed 
sufficiently  to  bring  the  topmost  sandstone  member  of  the  forma- 
tion within  340  feet  of  the  surface  on  the  crest  of  the  anticline. 


ESTIMATED  FUTURE  PRODUCTION  TABLE— GRASS  CREEK 

FIELD. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

600 

0 

11,000 

11,400 

22,000 

19,200 

1,000 

790 

12,000 

12,200 

23,000 

19,800 

2,000 

2,360 

13,000 

12,950 

24,000 

20,400 

3,000 

3,670 

14,000 

13,700 

25,000 

21,000 

4,000 

4,870 

15,000 

14,450 

26,000 

21,600 

5,000 

6,000 

16,000 

15,200 

27,000 

22,200 

6,000 

7,000 

17,000 

15,900 

28,000 

22,800 

7,000 

7,9.^)0 

18,000 

16,600 

29,000 

23,350 

8,000 

8,850 

19,000 

17,250 

30,000 

23,900 

9,000 

9,750 

20,000 

17,900 

31,000 

24,500 

10,000 

10,600 

21,000 

18,550 

32,000 

25,100 

MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 


145 


This  sandstone  is  water  bearing,  but  the  three  remaining  sand- 
stones of  this  series  are  productive  and  occur  at  depths  ranging 
from  560  to  1,600  feet.  The  wells  in  this  field  are  not  cased  so 
that  the  individual  sands  are  allowed  to  produce  separately,  there- 
fore, the  curves  represent  the  estimated  reserves  in  the  three  sands 
combined. 

In  working  up  these  data  it  was  found  necessary  to  make  use  of 
the  monthly  production  records,  and  as  these  represented  pipe- 
line runs  moving  averages  were  used  in  order  to  obtain  figures 
which  more  nearly  represented  the  actual  production  for  any  given 
month.  The  results  obtained  fully  justify  this  procedure.  In  this 
field  the  first  wells  were  drilled  in  1914  and  the  oil  run  through  the 
pipe  line  in  August,  1915.  The  spacing  in  this  field  is  4.4  acres 
per  well  and  the  gravity  of  thick  42°  Baume. 


Elk  Basin  Field,  Park  County,  Wyo. 

This  field  is  very  similar  to  Grass  Creek,  and  the  same  methods 
were  used  in  working  up  curves,  these  being  based  on  production  by 
months  and  moving  averages.  The  gravity  of  the  oil  is  42° 
Baume,  and  the  spacing  of  the  wells  4.4  acres  per  well.     Generally 

ESTIMATED  FUTURE  PRODUCTION  TABLE— ELK  BASIN 

FIELD. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

500 

0 

28,000 

17,900 

56,000 

32,300 

2,000 

1,300 

30,000 

19,000 

58,000 

33,300 

4,000 

2,850 

32,000 

20,100 

60,000 

34,300 

6,000 

4,350 

34,000 

21,150 

62,000 

35,300 

8,000 

5,750 

36,000 

22,200 

64,000 

36,200 

10,000 

7,100 

38,000 

23,250 

66,000 

37,200 

12,000 

8,400 

40,000 

24,300 

68,000 

38,100 

14,000 

9,700 

42,000 

25,350 

70,000 

39,100 

16,000 

10,900 

44,000 

27,400 

72,000 

40,000 

18,000 

11,100 

46,000 

26,400 

74,000 

41,000 

20,000 

13,300 

48,000 

28,400 

76,000 

41,900 

22,000 

14,500 

50,000 

29,400 

78,000 

42,900 

24,000 

15,700 

52,000 

30,400 

80,000 

43,800 

26,000 

16,800 

51,000 

31,400 

146  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

speaking,  the  operating  conditions  are  favorable.  The  structure  is 
an  elongated  comparatively  sharp  crested  anticline,  which  is 
highly  dissected  by  dip  faults.  These  conditions  give  rise  to  some 
irregularities  in  the  outline  of  the  oil-bearing  territory  on  the 
structure,  but  thus  far  appears  not  to  have  materially  affected 
the  production  of  individual  wells  located  directly  on  the  faults. 
The  first  wells  were  drilled  in  1915  and  the  oil  runs  through  the  pipe 
hue  began  June,  1916. 

FUTURE  PRODUCTION  CURVES  FOR  THE  CLAIFORNIA  OIL 

FIELDS. 

The  California  oil  fields  may  be  roughly  divided  into  two 
provinces,  the  first  province  occupying  both  sides  of  the  San 
Joaquin  Valley  and  commonly  known  as  the  Valley  fields,  and  the 
second  occupying  a  large  coastal  area  and  conmionly  known  as 
the  Coastal  fields.  The  Valley  fields,  with  one  exception,  lie  on 
the  west  side  of  the  San  Joaquin  Valley  and  produce  the  bulk  of 
their  oil  from  the  porous  Tertiary  sandstones,  which  have  been 
folded  into  arches  and  troughs — anticlines  and  synclines.  Although 
the  prevailing  type  of  structure  controlling  the  oil  accumulation  is 
relatively  sharply  folded  anticlines,  considerable  oil  has  been 
produced  from  omnoclines  and  synclines.  The  conditions  in  the 
Coastal  fields  are  similar  in  many  respects  to  those  of  the  Valley 
fields,  although  a  much  greater  variety  of  structure  is  present. 

The  bulk  of  the  oil  produced  in  California  comes  from  forma- 
tions of  Tertiary  age,  the  proportion  coming  from  the  older  under- 
lying Cretaceous  formations  being  practically  negligible.  The 
principal  rocks  comprising  the  oil-bearing  series  are  interbedded 
sandstones  and  shales,  the  oil  probably  originating  in  the  organic 
diatomaceous  shales  and  later  being  accumulated  in  pools  in 
the  overlying  or  underlying  porous  sandstones.  Throughout  a 
long  stratigraphic  range  of  these  Tertiary  rocks,  the  oil-bearing 
sandstones  occur,  those  in  one  field  at  one  horizon,  whereas  those 
in  a  near-by  field  may  be  encountered  at  an  entirely  different 
horizon. 

The  California  fields  are  usually  large  and  the  factors  affecting 
production  are  rather  variable — sometimes  even  in  the  same  area. 
For  this  reason,  in  preparing  curves  showing  the  average  future 
production  of  wells  of  varying  size,  it  was  necessary  to  divide  some 
of  the  larger  fields  into  individual  productive  units,  each  unit 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY  147 

including  all  the  wells  or  properties  producing  under  similar  con- 
ditions. 

Furthermore,  many  of  the  California  fields  are  underlain  by 
more  than  one  productive  oil  zone,  and  it  was  necessary  to  pre- 
pare curves  showing  the  average  future  production  of  wells  that 
produced  from  each  of  these  zones.  In  the  following  presenta- 
tion of  the  curves,  the  area  for  which  each  curve  is  designed  is 
described,  and  the  zone  from  which  the  wells  produce,  that  serve 
as  a  basis  for  the  curve,  is  stated. 

Occasionally  zone  A,  in  one  part  of  a  large  field  like  the  Midway 
field  may  be  geologically  equivalent  to  zone  B  in  another  part  of 
the  field.  No  attempt  has  been  made  to  correlate  these  zones 
from  one  area  to  another,  as  none  of  the  curves  applies  to  wells 
producing  from  a  single  zone  in  different  areas. 

Because  of  the  lack  of  data,  average  future  production  curves 
could  not  be  drawn  for  all  producing  areas.  Only  the  larger  areas 
are  covered.  Estimates  of  the  average  future  production  of  wells 
in  these  areas  made  by  using  the  curves  should  be  made  with 
caution  and  with  knowledge  of  the  fact  that  the  curves  represent 
average  conditions,  although  all  the  curves  presented  have  been 
carefully  checked  by  selecting  properties  at  random  and  making 
estimates  of  their  future  production  by  the  use  of  curves. 

It  should  be  noted  that  practically  all  the  curves  are  based  on 
the  records  of  individual  wells,  only  a  few  having  been  prepared 
from  the  tract  production  records.  For  this  reason,  estimates  of 
the  future  production  of  tracts  can  best  be  made  by  using  the 
former  curve  for  estimating  the  future  production  of  individual 
wells,  and  then  totaling  the  estimates  of  the  separate  wells.  In 
case  a  curve  has  been  prepared  from  records  of  tract  production,  an 
estimate  of  the  future  production  of  any  tract  in  the  area  may  be 
obtained  by  determining  the  average  production  per  well  during 
the  last  year,  determining  the  future  of  a  well  of  this  size  from  the 
curve  and  then  multiplying  this  estimate  by  the  number  of  wells. 
It  is  true  that  the  future  production  of  an  average  well  on  a  tract 
may  be  made  from  a  curve  based  on  the  production  records  of  indi- 
vidual wells.  The  practice  is  not  recommended,  however,  because 
of  the  greater  possibility  of  error.  ]\Iuch  closer  estimates  may  be 
made  if  the  curves  based  on  the  individual  wells  are  used  onlj^  for 
making  estimates  of  the  average  future  production  of  individual 
wells. 


148  MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 

The  following  examples  of  procedure  in  making  estimates  under 
certain  conditions  may  be  of  use : 

Case  I. — In  case  a  producer  desires  to  estimate  the  future  pro- 
duction of  a  tract  completely  drilled  on  wliich  the  production  is 
gradually  declining,  it  is  unnecessary  to  use  the  average  future 
production  curve  for  the  district  in  which  the  property  is  situated. 
Very  likely  a  much  closer  estimate  can  be  made  by  plotting  the 
annual  production  of  the  property  and  by  projecting  its  curve  as 
shown  in  Fig.  2  of  the  paper  on  "  Methods  of  estimating  recoverable 
underground  reserves  "  in  another  part  of  this  manual. 

Case  II. — If  a  property  is  so  nearly  drilled  up  that  drainage  has 
materially  affected  the  probable  initial  production  of  the  undrilled 
wells  on  the  proved  acreage,  a  curve  showing  the  average  annual 
production  per  well  may  be  plotted  and  projected  to  the  estimated 
economic  minimum.  The  production  for  any  future  year  may  be 
estimated  by  multiplying  the  reading  on  the  projected  curve  for 
that  3^ear  by  the  number  of  wells  to  be  producing.  In  this  manner 
the  undrilled  wells  are  considered.  This  method  can  not  be  used 
unless  drainage,  within  all  likelihood,  has  affected  the  oil  reserves 
under  the  undrilled  territory. 

Case  III. — A  variation  of  the  above  method  is  to  estimate  the 
future  production  of  the  drilled  wells  as  in  Case  I  or  II  and  deter- 
mine the  ultimate  production  per  acre  for  the  drilled  part  of  the 
tract  and  to  apply  these  determined  values  per  acre,  with  the 
proper  modifications,  to  the  undrilled  portion  of  the  tract  that  is 
practically  certain  to  produce  oil. 

Case  IV. — Still  another  method  is  as  follows :  Proceed  as  in  the 
first  part  of  Case  III.  Then  estimate  the  first  year's  production  of 
the  undrilled  wells,  preferably  by  using  as  a  basis  of  estimate  the 
first  year's  production  of  the  drilled  wells.  Determine  the  future 
of  wells  of  this  size  by  using  the  average  future  production  curve. 
The  future  production  of  the  proved  undrilled  land  will  be  the 
sum  of  the  estimated  first  year's  production  and  the  estimated 
production  thereafter. 

The  Midway-Sunset  Field. 

The  Midway-Sunset  field  is  so  large  and  producing  oil  under 
such  diverse  conditions  that  it  has  been  necessary  for  the  present 
work  to  divide  it  into  several  separate  areas,  each  area  containing 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY  149 

the  wells  that  produce  oil  under  practically  equivalent  conditions. 
In  some  parts  of  the  field  three  zones  are  productive. 

One  very  marked  feature  in  the  underground  geologic  condi- 
tions is  the  wedging  out  of  the  older  or  basal  beds  of  the  Etchegoin 
formation,  along  the  plane  of  unconformity  between  the  base  of 
the  McKittrick  formation  and  the  top  of  the  Maricopa  (Mon- 
terey) shale.  This  wedging  out  causes  a  decrease  in  thickness  of 
the  productive  zone,  or  the  entire  elimination  of  the  lower  zone 
toward  the  outcrop  to  the  west.  The  wells  southwest  of  the  line 
where  these  zones  combine  produce  under  different  conditions 
from  those  northeast  of  that  line.  For  that  reason,  the  area  west, 
southwest,  and  south  of  the  Buena  Vista  Hills  have  been  divided 
into  three  separate  areas,  and  an  average  future  production  curve 
prepared  for  each  area.  There  are  four  areas  considered  therefore 
in  the  Midway-Sunset  field: 

1.  The  Fellows  Area. 

2.  The  Twenty-five  Hill  Area. 

3.  The  Maricopa  Flat  Area. 

4.  The  Buena  Vista  Hills  Area. 

It  is  true  that  these  areas  do  not  include  all  the  wells  in  the  Mid- 
way-Sunset field,  but  the  scattered  wells  outside  these  areas  do  not 
provide  sufficiently  trustworthy  and  plentiful  records  upon  which  to 
base  curves. 


Fellows  Area,  Midway  Field,  California. 

This  area  includes  most  of  the  wells  producing  from  the  thick 
sand  caused  by  the  coalescence  of  the  two  zones  found  to  the  east. 
The  area  may  be  roughly  defined  as  including  all  those  wells  south- 
west of  a  line  drawn  as  follows :  Beginning  at  the  northwest  corner 
of  section  26,  township  3  south,  range  22  east,  proceed  southeast 
to  the  southeast  corner  of  the  same  section,  thence  to  a  point  h  mile 
north  of  the  southeast  corner  section  3G,  township  31  south,  range 
22  east,  and  thence  southeast  to  a  point  j  mile  north  of  the  center 
of  the  south  line  of  section  5,  township  32  south,  range  23  east, 
where  the  area  terminates. 

The  curve  was  prepared  from  the  individual  records  of  most  of 
the  wells  in  this  area. 


150 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 


ESTIMATED  FUTURE  PRODUCTION  TABLE— FELLOWS  AREA 
OF  THE  MIDWAY  FILED. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

1,000 

0 

27,000 

73,500 

64,000 

157,500 

2,000 

3,000 

28,000 

76,000 

66,000 

161,500 

3,000 

6,000 

29,000 

78,500 

68,000 

165,500 

4,000 

9,000 

30,000 

81,000 

70,000 

169,500 

5,000 

12,000 

31,000 

83,500 

72,000 

172,500 

6,000 

15,000 

32,000 

86,000 

74,000 

176,000 

7,000 

18,000 

33,000 

88,500 

76,000 

179,500 

8,000 

21,000 

34,000 

91,000 

78,000 

183,000 

9,000 

24,000 

35,000 

93,500 

80,000 

186,500 

10,000 

27,000 

36,000 

96,000 

85,000 

195,000 

11,000 

30,000 

37,000 

98,500 

90,000 

203,500 

12,000 

33,000 

38,000 

101,000 

95,000 

212,000 

13,000 

36,000 

39,000 

103,500 

100,000 

220,500 

14,000 

39,000 

40,000 

106,000 

105,000 

229,000 

15,000 

42,000 

42,000 

111,000 

110,000 

237,500 

16,000 

45,000 

44,000 

115,500 

115,000 

246,000 

17,000 

48,000 

46,000 

120,000 

120,000 

254,000 

18,000 

51,000 

48,000 

124,500 

125,000 

262,000 

19,000 

53,500 

50,000 

129,000 

130,000 

270,000 

20,000 

56,000 

52,000 

133,500 

135,000 

277,500 

21,000 

58,500 

54,000 

137,500 

140,000 

285,000 

22,000 

61,000 

56,000 

141,500 

145,000 

292,500 

23,000 

63,500 

58,000 

145,500 

150,000 

300,000 

24,000 

66,000 

60,000 

149,500 

155,000 

307,. 500 

25,000 

68,500 

62,000 

153,500 

160,000 

315,000 

26,000 

71,000 

Twenty-five  Hill  Area,  Midway  Field,  California. 

This  area  lies  southeast  of  the  Fellows  Area  and  includes  all 
wells  lying  southwest  of  a  line  extending  southeastward  from  a 
point  \  mile  south  of  the  center  of  section  5,  township  32  south, 
range  23  east,  to  the  center  of  the  south  line  of  section  15,  town- 
ship 32  south,  range  23  east,  thence  to  the  center  of  the  east  line  of 
section  23,  township  32  south,  range  23  east,  and  thence  to  the 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 


151 


center  of  the  south  line  of  section  30,  township  32  south,  range  24 
east.  All  wells  in  section  15,  township  31,  south,  range  22  east, 
and  those  producing  from  the  first  zone  only  in  sections  14  and  23, 
township  31  south,  range  22  east,  are  also  included  in  this  area, 
and  estimates  of  the  future  production  of  these  wells  may  be  made 
by  using  the  same  curve. 


ESTIMATED  FUTURE  PRODUCTION  TABLE— TWENTY-FIVE 
HILL  AREA. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

1,000 

0 

7,500 

43,700 

21,000 

80,900 

1,250 

2,800 

8,000 

45,800 

22,000 

83,000 

1,500 

5,400 

8,500 

47,700 

23,000 

85,100 

1,750 

7,900 

9,000 

49,500 

24,000 

87,100 

2,000 

10,300 

9,500 

51,200 

25,000 

89,100 

2,250 

12,600 

10,000 

52,900 

26,000 

91,000 

2,500 

14,700 

10,500 

54,600 

27,000 

93,100 

2,750 

16,700 

11,000 

56,200 

28,000 

95,100 

3,000 

18,600 

11,500 

57,700 

29,000 

97,100 

3,250 

20,400 

12,000 

59,200 

30,000 

99,100 

3,500 

22,200 

12,500 

60,700 

31,000 

101,100 

3,750 

23,900 

13,000 

62,100 

32,000 

103,100 

4,000 

25,600 

13,500 

63,400 

33,000 

105,100 

4,250 

27,200 

14,000 

64,700 

34,000 

107,100 

4,500 

28,800 

14,500 

66,000 

35,000 

109,100 

4,750 

30,300 

15,000 

67,300 

36,000 

111,100 

5,000 

31,700 

16,000 

69,800 

37,000 

113,100 

5,500 

34,300 

17,000 

72,200 

38,000 

115,100 

6,000 

36,800 

18,000 

74,500 

39,000 

117,100 

6,500 

39,200 

19,000 

76,700 

40,000 

119,000 

7,000 

41,500 

20,000 

78,800 

Maricopa  Flat  Area. 

The  curve  for  this  area  was  prepared  from  the  records  of  indi- 
vidual wells  that  produce  from  the  first  zone  only  in  the  area  known 
as  the  Maricopa  Flat  in  the  Sunset  field.  The  curve  should  be 
used  for  estimating  the  future  production  of  individual  wells  at 


152 


MANUAL  FOR   THE  OIL  AND   GAS   INDUSTRY 


present  producing  from  this  zone  and  for  making  similar  estimates 
of  other  wells  drilled  to  this  zone. 


FUTURE  PRODUCTION  TABLE  FOR  A  PORTION  OF  THE  SUNSET 
OIL  FILED,  CALIFORNIA,  MARICOPA  FLAT   AREAS. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

1,000 

0 

15,000 

62,900 

28,000 

94,600 

2,000 

7,800 

16,000 

65,700 

29,000 

96,800 

3,000 

14,500 

17,000 

68,400 

30,000 

99,000 

4,000 

20,500 

18,000 

71,100 

31,000 

101,200 

5,000 

26,000 

19,000 

73,700 

32,000 

103,400 

6,000 

31,000 

20,000 

76,200 

33,000 

105,600 

7,000 

35,600 

21,000 

78,500 

34,000 

107,800 

8,000 

40,000 

22,000 

80,900 

35,000 

110,000 

9,000 

44,000 

23,000 

83,200 

36,000 

112,100 

10,000 

47,700 

24,000 

85,500 

37,000 

114,200 

11,000 

51,000 

25,000 

87,800 

38,000 

116,200 

12,000 

54,100 

26,000 

90,100 

39,000 

118,200 

13,000 

57,100 

27,000 

92,400 

40,000 

120,200 

14,000 

60,000 

Buena  Vista  Hills  Area,  Midway  Field,  Calif. 


This  curve  was  prepared  from  the  records  of  individual  wells 
drilled  on  practically  drilled-up  tracts  in  the  Buena  Vista  Hills. 
The  only  records  omitted  in  making  the  curve  were  the  records  of 
such  wells  as  those  belonging  to  the  Honolulu  Consolidated  Oil  Co. 
in  section  6,  township  32  south,  range  24  east,  which  have  large 
drainage  areas  with  no,  or  very  little  interference,  thus  causing 
the  wells  to  decline  slowly. 

Practically  all  the  wells  in  this  area  were  treated  as  if  they  were 
producing  from  one  thick  zone,  for  in  nearly  all  parts  of  the  area 
where  a  division  can  be  made,  the  wells  now  produce  without  water 
from  both. 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY 


153 


ESTIMATED  FUTURE  PRODUCTION  TABLE— BUENA  VISTA 

HILLS. 


Average 
Production 
per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Parrels. 

2,000 

0 

72,000 

166,000 

195,000 

291,000 

4,000 

9,000 

76,000 

171,000 

200,000 

296,000 

6,000 

17,000 

80,000 

176,000 

205,000 

300,000 

8,000 

24,000 

84,000 

181,000 

210,000 

305,000 

10,000 

32,000 

88,000 

185,000 

215,000 

310,000 

12,000 

39,000 

92,000 

189,000 

220,000 

314,000 

14,000 

45,000 

96,000 

194,000 

225,000 

319,000 

16,000 

52,000 

100,000 

198,000 

230,000 

324,000 

18,000 

58,000 

105,000 

203,000 

235,000 

329,000 

20,000 

65,000 

110,000 

208,000 

240,000 

334,000 

22,000 

71,000 

115,000 

214,000 

245,000 

338,000 

24,000 

76,000 

120,000 

218,000 

250,000 

343,000 

26,000 

82,000 

125,000 

224,000 

255,000 

348,000 

28,000 

87,000 

130,000 

229,000 

260,000 

353,000 

30,000 

93,000 

135,000 

234,000 

265,000 

357,000 

32,000 

98,000 

140,000 

239,000 

270,000 

362,000 

34,000 

102,000 

145,000 

243,000 

275,000 

367,000 

36,000 

106,000 

150,000 

248,000 

280,000 

372,000 

38,000 

111,000 

155,000 

253,000 

285,000 

377,000 

40,000 

115,000 

160,000 

258,000 

290,000 

381,000 

44,000 

123,000 

105,000 

265,000 

295,000 

386,000 

48,000 

130,000 

170,000 

267,000 

300,000 

391,000 

52,000 

137,000 

175,000 

272,000 

305,000 

390,000 

56,000 

144,000 

180,000 

277,000 

310,000 

401,000 

60,000 

150,000 

185,000 

282,000 

315,000 

405,000 

64,000 

156,000 

190,000 

286,000 

320,000 

410,000 

68,000 

161,000 

McKittrick  Field,  Kern  County,  Calif. 


The  McKittrick  field  has  been  very  productive,  but  on  account 
of  complex  structure,  which  causes  the  wells  to  produce  different 
amounts  at  different  rates,  there  is  a  considerable  range  in  produc- 
tivity. The  curve  shown  was  prepared  from  the  production 
records  of  many  different  tracts  in  this  field.     Estimates  made  by 


154 


MANUAL   FOR  THE  OIL  AND   GAS   INDUSTRY 


the  use  of  this  curve  should  show  within  a  small  percentage  of 
error  the  amount  that  actually  will  be  produced. 


ESTIMATED  FUTURE  PRODUCTION  TABLE— McKITTRICK 

FIELD. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

1,000 

0 

10,000 

85,000 

28,000 

177,000 

1,500 

6,000 

11,000 

92,000 

29,000 

181,000 

2,000 

12,000 

12,000 

99,000 

30,000 

184,000 

2,500 

17,000 

13,000 

106,000 

32,000 

192,000 

3,000 

22,000 

14,000 

112,000 

34,000 

199,000 

3,500 

27,000 

15,000 

118,000 

36,000 

206,000 

4,000 

32,000 

16,000 

124,000 

38,000 

213,000 

4,500 

37,000 

17,000 

129,000 

40,000 

219,000 

5,000 

42,000 

18,000 

134,000 

42,000 

226,000 

5,500 

47,000 

19,000 

139,000 

44,000 

232,000 

6,000 

52,000 

20,000 

144,000 

46,000 

239,000 

6,500 

56,000 

21,000 

148,000 

48,000 

246,000 

7,000 

61,000 

22,000 

152,000 

50,000 

252,000 

7,500 

65,000 

23,000 

157,000 

52,000 

258,000 

8,000 

69,000 

24,000 

161,000 

54,000 

265,000 

8,500 

73,000 

25,000 

165,000 

56,000 

271,000 

9,000 

77,000 

26,000 

169,000 

58,000 

277,000 

9,500 

81,000 

27,000 

173,000 

60,000 

283,000 

Belridge  Field,  Kern  County,  Calif. 

The  Belridge  field  lies  between  the  Lost  Hills  and  McKittrick 
oil  fields,  on  an  anticline  extending  northwest-southeast.  There 
are  two  distinct  oil  zones  on  this  field,  but  most  of  the  oil  to  date  had 
come  from  the  upper  zone.  In  fact,  so  few  wells  have  been  drilled 
to  the  second  zone  that  practically  no  production  records  were 
available  for  the  preparation  of  a  curve.  The  curve  was  pre- 
pared from  the  records  of  individual  wells. 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY 


155 


ESTIMATED  FUTURE  PRODUCTION  TABLE— BELRIDGE   FIELD 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

1,000 

0 

25,000 

71,900 

58,000 

122,100 

2,000 

4,900 

26,000 

73,900 

60,000 

124,500 

3,000 

9,400 

27,000 

75,900 

62,000 

126,900 

4,000 

13,500 

28,000 

77,800 

64,000 

129,200 

5,000 

17,300 

29,000 

79,700 

66,000 

131,500 

6,000 

21,000 

30,000 

81,500 

68,000 

133,700 

7,000 

24,600 

31,000 

83,300 

70,000 

135,900 

8,000 

28,100 

32,000 

85,000 

72,000 

138,100 

9,000 

31,500 

33,000 

86,700 

74,000 

140,300 

10,000 

34,800 

34,000 

88,400 

76,000 

142,500 

11,000 

38,000 

35,000 

90,000 

78,000 

144,700 

12,000 

41,100 

36,000 

91,600 

80,000 

146,900 

13,000 

44,000 

37,000 

93,100 

85,000 

151,900 

14,000 

46,800 

38,000 

94,600 

90,000 

156,700 

15,000 

49,500 

39,000 

96,100 

95,000 

161,300 

16,000 

52,100 

40,000 

97,600 

100,000 

165,700 

17,000 

54,600 

42,000 

100,600 

105,000 

170,000 

18,000 

56,900 

44,000 

103,500 

110,000 

174,200 

19,000 

59,200 

46,000 

106,400 

115,000 

178,400 

20,000 

61,400 

48,000 

109,200 

120,000 

182,500 

21,000 

63,600. 

50,000 

111,900 

125,000 

186,500 

22,000 

65,800 

52,000 

114,500 

130,000 

190,400 

23,000 

67,900 

54,000 

117,100 

135,000 

194,200 

24,000 

69,900 

56,000 

119,600 

140,000 

197,900 

Lost  Hills  Field,  Kern  County,  Calif. 


This  field  is  located  between  the  Coalinga  and  Midway  oil  fields 
on  the  west  side  of  the  San  Joaquin  Valley.  The  structure  is  that 
of  an  anticline  that  plunges  southeastward.  The  greater  part  of 
the  known  producing  area  is  underlain  by  two  zones,  the  top  of  the 
first  of  which  is  encountered  at  depths  ranging  from  400  to  750 
feet  and  the  top  of  the  second  being  encountered  in  the  southern 
end  of  the  field  at  depths  ranging  from  1,500  to  1,900  feet.  In  the 
southern  end  of  the  field,  the  interval  between  the  zones  appears  to 
be  greater  than  in  the  northwestern  end  of  the  field. 


156 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY 


A  separate  curve  was  prepared  for  those  wells  producing  from 
the  second  zone,  but  it  was  found  to  be  practically  identical  with 
that  prepared  for  the  whole  field,  so  only  the  latter  is  given.  This 
curve  was  prepared  from  the  record  of  individual  wells. 


ESTIMATED  FUTURE  PRODUCTION  TABLE- 
FIELD. 


-LOST  HILLS 


Average 
Production 
per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

1,000 

0 

21,000 

57,800 

42,000 

99,900 

2,000 

4,000 

22,000 

60,100 

44,000 

103,500 

3,000 

8,000 

23,000 

62,400 

46,000 

107,100 

4,000 

11,600 

24,000 

64,600 

48,000 

110,700 

5,000 

15,000 

25,000 

66,800 

50,000 

114,300 

6,000 

18,200 

26,000 

69,000 

52,000 

117,900 

7,000 

21,200 

27,000 

71,100 

54,000 

121,500 

8,000 

24,200 

28,000 

73,200 

56,000 

125,000 

9,000 

27.000 

29,000 

75,200 

58,000 

128,500 

10,000 

29,800 

30,000 

77,200 

60,000 

131,900 

11,000 

32,600 

31,000 

79,200 

62,000 

135,200 

12,000 

35,400 

32,000 

81,200 

64,000 

138,400 

13,000 

38,100 

33,000 

83,200 

66,000 

141,600 

14,000 

49,700 

34,000 

85,200 

68,000 

144,800 

15,000 

43,300 

35,000 

87,100 

70,000 

148,000 

16,000 

45,800 

36,000 

89,000 

72,000 

151,200 

17,000 

48,200 

37,000 

90,000 

74,000 

154,400 

18,000 

50,600 

38,000 

92,700 

76,000 

157,600 

19,000 

53,200 

39,000 

94,500 

78,000 

160,800 

20,000 

55,500 

40,000 

96,300 

80,000 

164,000 

West  Side  Coalinga  Field,  Fresno  County,  Calif. 

This  field  is  located  on  a  monocline,  the  producing  strata  form 
one  zone,  ranging  in  thickness  from  200  to  325  feet,  approximately. 
The  records  indicate  at  least  three  sands  in  this  zone.  A  fourth 
has  been  recognized  in  a  part  of  the  area.  The  curve  shown  is 
designed  for  all  the  wells  in  the  West  Side  field,  and  was  prepared 
from  practically  all  the  available  trustworthy  data  that  could  be 
obtained  on  the  output  of  individual  wells.     It  should  be  remcm- 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY  157 

bered  that  this  curve  represents  the  average  future  production  of 
the  wells  of  different  sizes,  and  estimates  of  future  production  made 
by  using  this  curve  may  be  slightly  in  error  if  the  wells  for  which 
the  estimates  are  being  made  are  not  average  wells. 

ESTIMATED  FUTURE  PRODUCTION  TABLE— WEST  SIDE 
FIELD,  COALINGA. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

2,000 

0 

24,000 

107,000 

70,000 

236,500 

3,000 

6,000 

26,000 

115,500 

75,000 

245,500 

4,000 

11,500 

28,000 

124,000 

80,000 

254,000 

5,000 

16,000 

30,000 

132,000 

85,000 

262,000 

6,000 

21,000 

32,000 

140,000 

90,000 

270,000 

7,000 

26,000 

34,000 

147,500 

95,000 

277,500 

8,000 

31,000 

36,000 

155,000 

100,000 

285,000 

9,000 

36,000 

38,000 

162,000 

105,000 

292,500 

10,000 

41,000 

40,000 

168,500 

110,000 

300,000 

11,000 

46,000 

42,000 

174,500 

115,000 

307,500 

12,000 

51,000 

44,000 

180,500 

120,000 

315,000 

13,000 

56,000 

46,000 

186,000 

125,000 

322,500 

14,000 

61,000 

48,000 

191,000 

130,000 

330,000 

15,000 

66,000 

50,000 

196,000 

135,000 

337,000 

16,000 

71,000 

52,000 

201,000 

140,000 

344,000 

17,000 

75,500 

54,000 

205,500 

145,000 

351,000 

18,000 

80,000 

56,000 

210,000 

150,000 

358,000 

19,000 

84,500 

58,000 

214,000 

155,000 

365,000 

20,000 

89,000 

60,000 

218,000 

160,000 

372,000 

22,000 

98,000 

65,000 

227,500 

East  Side  Coalinga  Field,  Fresno  County,  Calif. 

This  field  is  located  on  an  anticline  which  plunges  to  the  south- 
eastward. Two  different  zones  produce  oil  on  the  East  Side.  The 
oil  from  the  first  zone  ranges  in  gravity  from  24  to  28°  Baumc,  and 
that  from  the  second  zone  from  22  to  24°  Baumc.  The  curve  shown 
in  the  figure  is  made  up  from  the  individual  production  records  of 
many  East  Side  wells.  It  may  be  used  for  estimating  the  future 
production  of  normal   individual  wells.     A  separate  curve  was 


158 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 


made  for  the  wells  in  that  portion  of  the  field  on  sections  21,  22,  27, 
and  28,  township  19  south,  range  15  east,  which  produces  from  both 
zones  but  the  results  were  practically  identical  with  those  derived 
from  the  curve  covering  all  the  wells  of  the  East  Side 

Consequently,  but  one  curve  is  given.  Estimates  made  from  it 
should  be  carefully  examined  and  consideration  given  to  the  esti- 
mate of  the  future  production  of  unusual  wells,  of  which  there  are 
many  in  this  area. 


ESTIMATED  FUTURE  PRODUCTION  TABLE— EAST  SIDE 
FIELD,  COALINGA. 


Average 
Production 
per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

1,000 

0 

27,000 

107,700 

64,000 

209,900 

2,000 

6,500 

28,000 

110,900 

66,000 

214,800 

3,000 

12,000 

29,000 

114,000 

68,000 

219,700 

4,000 

17,200 

30,000 

117,100 

70,000 

224,500 

5,000 

22,200 

31,000 

120,200 

72,000 

229,300 

6,000 

27,000 

32,000 

123,200 

74,000 

234,000 

7,000 

31,700 

33,000 

126,200 

76,000 

238,700 

8,000 

36,200 

34,000 

129,200 

78,000 

243,400 

9,000 

40,600 

35,000 

132,200 

80,000 

248,000 

10,000 

44,800 

30,000 

135,200 

85,000 

259,500 

11,000 

48,900 

37,000 

138,200 

90,000 

270,900 

12,000 

53,000 

38,000 

141,200 

95,000 

282,200 

13,000 

57,000 

39,000 

144,100 

100,000 

293,300 

14,000 

61,000 

40,000 

147,000 

105,000 

304,200 

15,000 

64,900 

42,000 

152,800 

110,000 

314,900 

16,000 

68,800 

44,000 

158,500 

115,000 

325,500 

17,000 

72,600 

46,000 

164,000 

120,000 

336,100 

18,000 

76,200 

48,000 

169,400 

125,000 

346,600 

19,000 

79,800 

50,000 

174,700 

130,000 

357,000 

20,000 

83,400 

52,000 

179,800 

135,000 

367,400 

21,000 

87,000 

54,000 

184,900 

140,000 

377,700 

22,000 

90,500 

56,000 

190,000 

145,000 

387,900 

23,000 

94,000 

58,000 

195,000 

150,000 

398,000 

24,000 

97,500 

60,000 

200,000 

155,000 

408,000 

25,000 

101,000 

62,000 

205,000 

160,000 

418,000 

26,000 

104,400 

3(^000.  ^Ciooo  st^ooo.  eciooo  .70,000  .80,000 

^\^e:ra^&    Pn:?duct/on  per"     yy&//    c/c^Hng     Taxah/s      V_eoc,     In    Barr^/s. 

FIG.   11.— ESTIMATED   AVERAGE    FUTURE   PRODUCTION   CURVES,   PART  OF  CALIFORNIA    FIELD. 


(To  face  page  159.) 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 


159 


The  Kern  River  Field,  Kern  County,  Calif. 

The  Kern  River  field  has  been  one  of  the  most  productive  per 
acre  in  the  State.  During  the  year  1918  this  field  ranked  fourth 
in  production. 

No  records  of  individual  wells  were  available  so  the  curve  pre- 
sented was  made  up  from  the  records  of  the  past  production  of  dif- 
ferent tracts.  The  curve  is  applicable  to  any  tract  in  the  field,  but 
estimates  made  of  future  production  should  be  made  with  a  full 
knowledge  of  the  conditions  existing  on  the  lease  for  which  the 
estimate  is  desired. 


ESTIMATED  FUTURE  PRODUCTION  TABLE— KERN  RIVER, 

OIL  FIELD. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

1,000 

0 

7,500 

51,000 

15,000 

76,200 

1,200 

5,500 

8,000 

52,700 

15,500 

77,800 

1,400 

10,000 

8,500 

54,400 

16,000 

79,400 

1,600 

14,000 

9,000 

56,100 

16,500 

81,000 

1,800 

17,000 

9,500 

57,800 

17,000 

82,600 

2,000 

19,800 

10,000 

59,500 

17,500 

84,200 

2,500 

25,500 

10,500 

61,200 

18,000 

85,800 

3,000 

30,000 

11,000 

62,900 

18,500 

87,400 

3,500 

33,800 

11,500 

64,600 

19,000 

89,000 

4,000 

36,600 

12,000 

66,300 

19,500 

90,500 

4,500 

39,400 

12,500 

68,000 

20,000 

92,000 

5,000 

41,700 

13,000 

69,700 

20,500 

93,500 

5,500 

43,700 

13,500 

71,400 

21,000 

95,000 

6,000 

45,600 

14,000 

73,000 

21,500 

96,500 

6,500 

47,400 

14,500 

74,600 

22,000 

98,000 

7,000 

49,200 

Santa  Maria  Field,  Santa  Barbara  County,  Calif. 

The  curve  for  this  field  was  made  up  from  the  production  records 
of  difi"erent  tracts  producing  in  the  old  Santa  Maria  field.  The 
Lompoc,  Cat  Canyon,  and  Casmalia  fields  were  not  included.  The 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY  159 

The  Kern  River  Field,  Kern  County,  Calif. 

The  Kern  River  field  has  been  one  of  the  most  productive  per 
acre  in  the  State.  During  the  year  1918  this  field  ranked  fourth 
in  production. 

No  records  of  individual  wells  were  available  so  the  curve  pre- 
sented was  made  up  from  the  records  of  the  past  production  of  dif- 
ferent tracts.  The  curve  is  applicable  to  any  tract  in  the  field,  but 
estimates  made  of  future  production  should  be  made  with  a  full 
knowledge  of  the  conditions  existing  on  the  lease  for  which  the 
estimate  is  desired. 


ESTIMATED  FUTURE  PRODUCTION  TABLE— KERN  RIVER, 

OIL  FIELD. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

1,000 

0 

7,500 

51,000 

15,000 

76,200 

1,200 

5,500 

8,000 

52,700 

15,500 

77,800 

1,400 

10,000 

8,500 

54,400 

16,000 

79,400 

1,600 

14,000 

9,000 

56,100 

16,500 

81,000 

1,800 

17,000 

9,500 

57,800 

17,000 

82,600 

2,000 

19,800 

10,000 

59,500 

17,500 

84,200 

2,500 

25,500 

10,500 

61,200 

18,000 

85,800 

3,000 

30,000 

11,000 

62,900 

18,500 

87,400 

3,500 

33,800 

11,500 

64,600 

19,000 

89,000 

4,000 

36,600 

12,000 

66,300 

19,500 

90,500 

4,500 

39,400 

12,500 

68,000 

20,000 

92,000 

5,000 

41,700 

13,000 

69,700 

20,500 

93,500 

5,500 

43,700 

13,500 

71,400 

21,000 

95,000 

6,000 

45,600 

14,000 

73,000 

21,500 

96,500 

6,500 

47,400 

14,500 

74,600 

22,000 

98,000 

7,000 

49,200 

Santa  Maria  Field,  Santa  Barbara  County,  Calif. 


The  curve  for  this  field  was  made  up  from  the  production  records 
of  different  tracts  producing  in  the  old  Santa  Maria  field.  The 
Lompoc,  Cat  Canyon,  and  Casmalia  fields  were  not  included.  The 


160 


MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY 


records  used  are  of  tracts  wherein  the  wells  produce  from  the  sec- 
ond and  third  zones.  Some  of  the  wells  produce  from  only  one 
zone,  but  many  produce  from  both. 


ESTIMATED  FUTURE  PRODUCTION  TABLE- 
MARIA  OIL  FIELD. 


-OLD  SANTA 


Average 

Estimated 

Average 

Estimated 

Average 

Estimated 

Production 

Average 

Production 

Average 

Production 

Average 

per  Well 
During  Tax- 

Future 

per  Well 

Future 

per  Well 

Future 

Production 

During  Tax- 

Production 

During  Tax- 

Production 

able  Year. 

per  Well. 

able  Year. 

per  Well. 

able  Year. 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

2,000 

0 

21,000 

145,800 

42,000 

217,400 

2,500 

4,800 

22,000 

150,500 

44,000 

222,800 

3,000 

9,500 

23,000 

154,900 

46,000 

228,200 

4,000 

18,800 

24,000 

159,000 

48,000 

233,600 

5,000 

27,900 

25,000 

163,000 

50,000 

239,000 

6,000 

37,000 

26,000 

167,000 

52,000 

244,200 

7,000 

46,000 

27,000 

170,900 

54,000 

249,400 

8,000 

54,900 

28,000 

174,800 

56,000 

254,600 

9,000 

63,600 

29,000 

178,500 

58,000 

259,800 

10,000 

72,000 

30,000 

182,000 

60,000 

265,000 

11,000 

80,100 

31,000 

185,300 

62,000 

269,800 

12,000 

88,000 

32,000 

188,500 

64,000 

274,600 

13,000 

95,600 

33,000 

191,600 

66,000 

279,400 

14,000 

102,900 

34,000 

194,600 

68,000 

284,200 

15,000 

110,000 

35,000 

197,600 

70,000 

289,000 

16,000 

116,800 

36,000 

200,500 

72,000 

293,500 

17,000 

123,300 

37,000 

203,400 

74,000 

298,000 

18,000 

129,500 

38,000 

206,300 

76,000 

302,500 

19,000 

134,500 

39,000 

209,200 

78,000 

307,000 

20,000 

140,800 

40,000 

212,000 

80,000 

311,500 

Ventura  County,  Calif. 

In  the  region  south  of  the  Santa  Clara  River  enough  data 
could  be  obtained  only  in  one  area  to  prepare  an  average  future 
production  curve.  This  is  the  Shields  Canyon  area,  sections  3  and 
4,  township  3  north,  range  19  west.  Two  sands  are  productive, 
but  the  curve  shown  is  based  on  the  records  of  individual  wells 
drilled  to  the  upper  sand  only. 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY 


161 


ESTIMATED  FUTURE  PRODUCTION  TABLE— VENTURA  FIELD. 


Average 
Production 

per  Well 
Durins  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

500 

0 

10,500 

23,100 

21,500 

34,800 

600 

1,300 

11,000 

23,700 

22,000 

35,300 

800 

3,200 

11,500 

24,300 

22,500 

35,800 

1,000 

4,700 

12,000 

24,900 

23,000 

36,300 

1,200 

5,800 

12,500 

25,500 

23,500 

36,700 

1,500 

7,200 

13,000 

26,100 

24,000 

37,200 

2,000 

8,900 

13,500 

26,700 

24,500 

37,600 

2,500 

10,300 

14,000 

27,300 

25,000 

38,100 

3,000 

11,400 

14,500 

27,800 

25,500 

38,600 

3,500 

12,400 

15,000 

28,300 

26,000 

39,000 

4,000 

13,300 

15,500 

28,800 

26,500 

39,400 

4,500 

14,200 

16,000 

29,300 

27,000 

39,900 

5,000 

15,000 

16,500 

29,800 

27,500 

40,300 

5,500 

15,800 

17,000 

30,300 

28,000 

40,800 

6,000 

16,600 

17,500 

30,800 

28,500 

41,200 

6,500 

17,400 

18,000 

31,300 

29,000 

41,600 

7,000 

18,200 

18,500 

31,800 

29,500 

42,100 

7,500 

18,900 

19,000 

32,300 

30,000 

42,600 

8,000 

19,600 

19,500 

32,800 

30,500 

43,000 

8,500 

20,300 

20,000 

33,300 

31,000 

43,500 

9,000 

21,000 

20,500 

33,800 

31,500 

43,900 

9,500 

21,700 

21,000 

34,300 

32,000 

44,300 

10,000 

22,400 

Salt  Lake  Field,  Los  Aiigeles  Counttj,  Calif. 


The  Salt  Lake  field  lies  between  Los  Angeles  and  the  Pacific 
Ocean.  The  curve  shown  was  prepared  from  the  records  of  several 
productive  properties  in  that  field  instead  of  from  the  records  of 
individual  w^ells.  The  wells  in  this  field  produce  from  the  Puente 
formation,  from  a  zone  about  800  feet  thick,  consisting  of  the  usual 
alternation  of  sand,  sandy  shale  and  shale. 


162  MANUAL   FOR  THE   OIL   AND   GAS   INDUSTRY 


ESTIMATED  FUTURE  PRODUCTION  TABLE— SALT  LAKE 

FIELD. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

1,000 

0 

28,000 

113,000 

55,000 

156,100 

2,000 

6,000 

29,000 

115,000 

56,000 

157,300 

3,000 

11,800 

30,000 

117,000 

57,000 

158,500 

4,000 

17,400 

31,000 

118,800 

58,000 

159,700 

5,000 

22,800 

32,000 

120,600 

59,000 

160,900 

6,000 

28,000 

33,000 

122,400 

60,000 

162,100 

7,000 

33,200 

34,000 

124,200 

61,000 

163,300 

8,000 

38,200 

35,000 

126,000 

62,000 

164,500 

9,000 

43,200 

36,000 

127,800 

63,000 

165,700 

10,000 

48,000 

37,000 

129,600 

64,000 

166,900 

11,000 

52,800 

38,000 

131,400 

65,000 

168,100 

12,000 

57,600 

39,000 

133,200 

66,000 

169,300 

13,000 

62,200 

40,000 

134,800 

67,000 

170,500 

14,000 

66,800 

41,000 

136,400 

68,000 

171,700 

15,000 

71,400 

42,000 

138,000 

69,000 

172,900 

16,000 

75,800 

43,000 

139,600 

70,000 

174,000 

17,000 

80,000 

44,000 

141,100 

71,000 

175,100 

18,000 

84,000 

45,000 

142,600 

72,000 

176,200 

19,000 

87,800 

46,000 

144,100 

73,000 

177,300 

20,000 

91,400 

47,000 

145,600 

74,000 

178,400 

21,000 

94,800 

48,000 

147,000 

75,000 

179,500 

22,000 

98,000 

49,000 

148,400 

76,000 

180,600 

23,000 

101,000 

50,000 

149,800 

77,000 

181,700 

24,000 

103,800 

51,000 

151,100 

78,000 

182,800 

25,000 

106,400 

52,000 

152,400 

79,000 

183,900 

26,000 

108,800 

53,000 

153,700 

80,000 

185,000 

27,000 

111,100 

54,000 

154,900 

Whittier  Field,  Los  Ajigeles  Countij,  Calif. 

In  this  field  nearly  all  the  wells  produce  from  the  Puente  forma- 
tion on  the  southwest  side  of  the  Puente  fault.  There  are  three 
fairly  distinct  zones  and  most  of  the  wells  penetrate  two.  The 
curve  shown  in  Fig.  12  is  based  on  the  action  of  individual  wells  in 
sections  22  and  23  township  2  south,  range  11  west.  Most  of  these 
wells  produced  from  one  zone  for  a  number  of  years  and  were 


\  iO,000  iZJSOO  I^OQO  fKSOO  S0,0O0  22^00  ZSiOOO  Z7,SOO  jqooo  Jl^SOO 

Ai^enagrei^  Rrocfucfion  pet"   Wefii   duHng    Ta^^abfe-     Yean,     fn    Barre/s, 

FIG.  12.— ESTIMATED  AVERAGE  FUTURE  PRODUCTION  CURVtS.   PART  OF  CALIFORNIA  FIELD. 


{To  face  page  163.) 


MANUAL  FOR  THE  OIL  AND  GAS   INDUSTRY 


163 


deepened  in  1915  to  1917  to  another  zone,  which  restored  them  to  a 
condition  of  flush  production.  For  this  reason  estimates  of  future 
production  from  this  curve  should  be  made  with  caution. 


ESTIMATED  FUTURE  PRODUCTION  TABLE— WHITTIER 

FIELD. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

400 

0 

10,500 

34,100 

21,500 

62,300 

600 

1,100 

11,000 

35,400 

22,000 

63,600 

800 

2,100 

11,500 

36,700 

22,500 

64,900 

1,000 

3,000 

12,000 

37,900 

23,000 

66,200 

1,500 

5,300 

12,500 

39,200 

23,500 

67,500 

2,000 

7,300 

13,000 

40,500 

24,000 

68,800 

2,500 

9,200 

13,500 

41,800 

24,500 

70,100 

3,000 

11,200 

14,000 

43,100 

25,000 

71,400 

3,500 

13,100 

14,500 

44,300 

.25,500 

72,700 

4,000 

14,800 

15,000 

45,600 

26,000 

74,000 

4,500 

16,500 

15,500 

46,900 

26,500 

75,300 

5,000 

18,200 

16,000 

48,200 

27,000 

76,600 

5,500 

19,800 

16,500 

49,500 

27,500 

77,900 

6,000 

21,300 

17,000 

50,800 

28,000 

79,200 

6,500 

22,800 

17,500 

52,100 

28,500 

80,400 

7,000 

24,300 

18,000 

53,400 

29,000 

81,700 

7,500 

25,800 

18,500 

54,600 

29,500 

83,000 

8,000 

27,200 

19,000 

55,900 

30,000 

84,300 

8,500 

28,600 

19,500 

57,200 

30,500 

85,600 

9,000 

30,000 

20,000 

58,500 

31,000 

86,900 

9,500 

31,300 

20,500 

59,800 

31,500 

88,200 

10,000 

32,700 

21,000 

61,100 

32,000 

89,400 

West  Coyote  Field,  Los  Angeles  County,  Calif. 

The  West  Coyote  field  Hes  a  few  miles  south  of  the  old  Whittier 
field,  most  of  the  productive  wells  having  been  drilled  in  sections 
17,  18,  19  and  20,  township  3  south,  range  10  west,  and  in  sections 
13  and  24,  township  3  south,  range  11  west.  The  curve  shown  is 
based  on  the  records  of  practically  all  the  individual  wells  in  that 
area. 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY 


163 


deepened  in  1915  to  1917  to  another  zone,  which  restored  them  to  a 
condition  of  flush  production.  For  this  reason  estimates  of  future 
production  from  this  curve  should  be  made  with  caution. 


ESTIMATED  FUTURE  PRODUCTION  TABLE— WHITTIER 

FIELD. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

400 

0 

10,500 

34,100 

21,500 

62,300 

600 

1,100 

11,000 

35,400 

22,000 

63,600 

800 

2,100 

11,500 

36,700 

22,500 

64,900 

1,000 

3,000 

12,000 

37,900 

23,000 

66,200 

1,500 

5,300 

12,500 

39,200 

23,500 

67,500 

2,000 

7,300 

13,000 

40,500 

24,000 

68,800 

2,500 

9,200 

13,500 

41,800 

24,500 

70,100 

3,000 

11,200 

14,000 

43,100 

25,000 

71,400 

3,500 

13,100 

14,500 

44,300 

.25,500 

72,700 

4,000 

14,800 

15,000 

45,600 

26,000 

74,000 

4,500 

16,500 

15,500 

46,900 

26,500 

75,300 

5,000 

18,200 

16,000 

48,200 

27,000 

76,600 

5,500 

19,800 

16,500 

49,500 

27,500 

77,900 

6,000 

21,300 

17,000 

50,800 

28,000 

79,200 

6,500 

22,800 

17,500 

52,100 

28,500 

80,400 

7,000 

24,300 

18,000 

53,400 

29,000 

81,700 

7,500 

25,800 

18,500 

54,600 

29,500 

83,000 

8,000 

27,200 

19,000 

55,900 

30,000 

84,300 

8,500 

28,600 

19,500 

57,200 

30,500 

85,600 

9,000 

30,000 

20,000 

58,500 

31,000 

86,900 

9,500 

31,300 

20,500 

59,800 

31,500 

88,200 

10,000 

32,700 

21,000 

61,100 

32,000 

89,400 

West  Coyote  Field,  Los  Angeles  County,  Calif. 

The  West  Coyote  field  lies  a  few  miles  south  of  the  old  Whittier 
field,  most  of  the  productive  wells  having  been  drilled  in  sections 
17,  18,  19  and  20,  township  3  south,  range  10  west,  and  in  sections 
13  and  24,  township  3  south,  range  11  west.  The  curve  shown  is 
based  on  the  records  of  practically  all  the  individual  wells  in  that 
area. 


164 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 


ESTIMATED  FUTURE  PRODUCTION  TABLE,   WEST  COYOTE 

FIELD. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 
per  Wellj 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

2,000 

0 

66,000 

162,800 

174,000 

249,400 

4,000 

7,200 

68,000 

165,200 

178,000 

252,300 

6,000 

14,300 

70,000 

167,500 

182,000 

255,200 

8,000 

21,400 

72,000 

169,800 

186,000 

258,100 

10,000 

28,500 

74,000 

172,000 

190,000 

261,000 

12,000 

35,500 

76,000 

174,100 

195,000 

264,800 

14,000 

42,400 

78,000 

176,100 

200,000 

268,500 

16,000 

49,200 

80,000 

178,000 

205,000 

272,200 

18,000 

55,900 

82,000 

179,800 

210,000 

275,800 

20,000 

62,500 

86,000 

183,200 

215,000 

279,400 

22,000 

69,000 

90,000 

186,500 

220,000 

283,000 

24,000 

75,400 

94,000 

189,700 

225,000 

286,700 

26,000 

81,700 

98,000 

192,900 

230,000 

290,300 

28,000 

87,900 

102,000 

196,000 

235,000 

293,900 

30,000 

94,000 

106,000 

199,000 

240,000 

297,500 

32,000 

99,800 

110,000 

202,000 

245,000 

301,200 

34,000 

105,200 

114,000 

205,000 

250,000 

304,800 

36,000 

110,200 

118,000 

208,000 

255,000 

308,400 

38,000 

115,000 

122,000 

211,000 

260,000 

312,000 

40,000 

119,500 

126,000 

214,000 

265,000 

315,700 

42,000 

123,800 

130,000 

217,000 

270,000 

319,300 

44,000 

128,000 

134,000 

220,000 

275,000 

322,900 

46,000 

132,100 

138,000 

223,000 

280,000 

326,500 

48,000 

136,100 

142,000 

226,000 

285,000 

330,200 

50,000 

140,000 

146,000 

229,000 

290,000 

334,000 

52,000 

143,700 

150,000 

232,000 

295,000 

337,800 

54,000 

147,200 

154,000 

234,900 

300,000 

341,500 

56,000 

150,300 

158,000 

237,800 

305,000 

345,200 

58,000 

153,000 

162,000 

240,700 

310,000 

348,800 

60,000 

155,500 

166,000 

243,600 

315,000 

352,400 

62,000 

158,000 

170,000 

246,500 

320,000 

356,000 

64,000 

160,400 

Fullerton  Field,  Los  Angeles  County,  Calif. 

This  field  is  sometimes  called  the  La  Habra  field,  and  consists 
of  those  wells  along  the  eastward  extension  of  the   Coyote  hills 


MANUAL   FOR  THE   OIL   AND   GAS   INDUSTRY 


165 


near  Fullerton.  Production  is  obtained  from  a  fairly  well-defined 
anticline.  Figure  shows  the  average  future  production  curve  for 
the  average  wells  of  different  output  in  this  field.  It  was  prepared 
from  records  of  individual  wells. 

ESTIMATED  FUTURE  PRODUCTION  TABLE— FULLERTON  OIL 
FIELD,  LA  HABRA  GROUP. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

2,000 

0 

27,000 

78,100 

64,000 

152,000 

2,500 

4,500 

28,000 

80,400 

66,000 

155,500 

3,000 

9,000 

29,000 

82,700 

68,000 

159,000 

4,000 

14,500 

30,000 

85,000 

70,000 

162,500 

5,000 

19,500 

31,000 

87,200 

72,000 

165,900 

6,000 

23,500 

32,000 

89,400 

74,000 

169,300 

7,000 

27,000 

33,000 

91,600 

76,000 

172,700 

8,000 

30,000 

34,000 

93,800 

78,000 

176,100 

9,000 

32,800 

35,000 

96,000 

80,000 

179,500 

10,000 

35,500 

36,000 

98,200 

85,000 

188,000 

11,000 

38,200 

37,000 

100,400 

90,000 

196,000 

12,000 

40,900 

38,000 

102,600 

95,000 

204,000 

13,000 

43,600 

39,000 

104,700 

100,000 

212,000 

14,000 

46,300 

40,000 

106,800 

105,000 

219,500 

15,000 

49,000 

42,000 

111,000 

110,000 

227,000 

16,000 

51,500 

44,000 

115,000 

115,000 

234,500 

17,000 

54,000 

46,000 

119,000 

124,000 

242,000 

18,000 

56,500 

48,000 

123,000 

125,000 

249,500 

19,000 

59,000 

50,000 

127,000 

130,000 

257,000 

20,000 

61,500 

52,000 

130,600 

135,000 

264,500 

21,000 

63,900 

54,000 

134,200 

140,000 

271,500 

22,000 

66,300 

56,000 

137,800 

145,000 

278,500 

23,000 

68,700 

58,000 

141,440 

150,000 

285,000 

24,000 

71,100 

60,000 

145,000 

155,000 

291,500 

25,000 

73,500 

62,000 

148,500 

160,000 

298,000 

26,000 

75,800 

Olinda  Field,  Los  Angeles  County,  Calif. 

Fig.  12  shows  the  average  future  production  curve  for  the 
Olinda  field.  Production  in  this  field  comes  from  the  Puente  fault 
zone  and  the  wells  as  a  rule  have  rather  large  future  productions 


166 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY 


for  their  size.  The  curve  was  compiled  from  all  available  records 
or  production  of  different  tracts.  The  same  caution  should  be  used 
in  making  estimates  of  the  future  production  of  wells  in  this  field 
as  are  used  in  other  fields.  Consideration  should  always  be  given 
the  local  conditions  governing  production  on  the  tract  for  which 
the  estimate  is  to  be  made. 

ESTIMATED  FUTURE  PRODUCTION  TABLE— OLINDA  FIELD. 


Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Average 
Production 

per  Well 

During  Tax-j 

able  Year. 

Estimated 

Average 

Future 

Production 

per  Well. 

Average 
Production 

per  Well 
During  Tax- 
able Year. 

Estimated 
Average 
Future 

Production 
per  Well. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

2,000 

0 

17,000 

141,000 

32,000 

252,000 

3,000 

10,000 

18,000 

150,000 

33,000 

257,000 

4,000 

20,000 

19,000 

158,500 

34,000 

261,500 

5,000 

30,000 

20,000 

167,000 

35,000 

266,000 

6,000 

40,000 

21,000 

175,000 

36,000 

270,000 

7,000 

50,000 

22,000 

183,000 

37,000 

273,000 

8,000 

59,500 

23,000 

191,000 

38,000 

275,500 

9,000 

69,000 

24,000 

198,500 

39,000 

277,500 

10,000 

78,000 

25,000 

206,000 

40,000 

279,500 

11,000 

87,000 

26,000 

213,500 

41,000 

281,000 

12,000 

96,000 

27,000 

221,000 

42,000 

282,500 

13,000 

105,000 

28,000 

228,000 

43,000 

284,000 

14,000 

114,000 

29,000 

235,000 

44,000 

285,500 

15,000 

123,000 

30,000 

241,500 

45,000 

287,000 

16,000 

132,000 

31,000 

247,000 

GULF  COAST  OF  TEXAS  AND  LOUISIANA. 


Curves  and  tables  for  the  Gulf  coast  fields  of  Texas  and  Lou- 
isiana are  in  preparation. 


_  —                                                                            -  - 

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Z 

7-            A^ 

/ 

y 

_ _- --y 

z 

/ 

^^ 

7 

J 

/ 

--  J 

Jl 

2 

/ 

^l 

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/ 

_ __>_ 

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7 

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t 

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300                     350                     400                     450                      500                     550 

g  Last  Four  Months  of  Taxable  Year,  in  Barrels 


(^To  face  page  167.) 


:   /^ 

/ 

/ 

/ 

/ 

/ 

7000 

/ 

■- 

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.'>y^ 

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0  / 

.N»y 

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2000 

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....     ,.., —  _,  _ 

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, 

Average  Monthly  Production  per  Welt  during  Last  Four  Months  of  Taxable  Year,  in  Barrels 

(To  face  page  167.) 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY  167 


TABLES  FOR  THE  ESTIMATION  OF  OIL  RESERVES  IN  THE 
GULF  COAST  OLL  FIELDS 

In  issuing  the  tables  included  in  this  paper,  it  is  recognized 
that  many  wells  or  groups  of  wells  may  deviate  materially  from  the 
average  given.  Owing  to  high  gas  pressures  and  the  unconsol- 
idated nature  of  the  sands,  wells  in  the  Gulf  Coast  field  come  in 
with  a  very  large  production  which  drops  rapidly  but  irregularly. 
When  production  has  dropped  to  a  point  yielding  little  profit,  wells 
are  commonly  reworked,  and  not  infrequently  the  result  is  a  reju- 
venation to  another  period  of  practically  flush  production.  In 
some  cases,  a  single  well  may  go  through  a  series  of  production 
declines  and  revivals.  The  behavior  is  so  erratic  that  averages 
apply  only  in  a  broadly  general  way.  In  the  fields  where  the 
gas  pressures  have  been  practically  exhausted,  violent  fluctuations 
of  this  sort  are  not  so  common,  but  even  in  these  fields  the  pro- 
duction of  individual  wells  is  erratic.  The  high  flush  production 
with  rapid  decline  may  cause  serious  overestimation  of  reserves  if  a 
well  comes  in,  or  is  cleaned  out  in  the  last  month  of  the  taxable 
year. 

The  tables  submitted  herewith  have  been  compiled  from  records 
of  a  large  number  of  wells,  many  of  which  were  being  reworked 
from  time  to  time,  and  consequently,  represent  the  average  well. 
In  the  older  fields  where  the  gas  pressure  has  been  largely  ex- 
hausted and  many  of  the  sands  have  been  flooded,  only  records  of 
recent  years  have  been  used  in  the  compilation. 

Curves  are  not  included,  as  it  has  been  thought  best  to  get 
these  data  before  the  operators  at  once,  rather  than  to  wait  for 
plates  to  be  made.  If  it  is  felt  by  the  user  that  a  graphic  represen- 
tation is  necessary  or  desirable,  a  curve  can  be  constructed  in  a  few 
moments  from  the  figures  given  by  any  engineer.  It  should  be 
noted  also  that  future  production  is  not  based  upon  average  pro- 
duction for  taxable  year  as  in  the  "  Manual  for  the  Oil  and  Gas 
Industry,"  but  on  the  average  production  for  the  last  month  of  the 
taxable  year. 

Humble  Field. 

The  initial  production  of  the  pool  was  from  the  "  cap  rock." 
This  is  a  porous  formation,  which  contained  oil  under  high  pres- 


MANUAL  FOR  THE  OIL  AND   GAS   INDUSTRY  167 


TABLES  FOR  THE  ESTIMATION  OF  OIL  RESERVES  IN  THE 
GULF  COAST  OIL  FIELDS 

In  issuing  the  tables  included  in  this  paper,  it  is  recognized 
that  many  wells  or  groups  of  wells  may  deviate  materially  from  the 
average  given.  Owing  to  high  gas  pressures  and  the  unconsol- 
idated nature  of  the  sands,  wells  in  the  Gulf  Coast  field  come  in 
with  a  very  large  production  which  drops  rapidly  but  irregularly. 
When  production  has  dropped  to  a  point  yielding  little  profit,  wells 
are  commonly  reworked,  and  not  infrequently  the  result  is  a  reju- 
venation to  another  period  of  practically  flush  production.  In 
some  cases,  a  single  well  may  go  through  a  series  of  production 
declines  and  revivals.  The  behavior  is  so  erratic  that  averages 
apply  only  in  a  broadly  general  way.  In  the  fields  where  the 
gas  pressures  have  been  practically  exhausted,  violent  fluctuations 
of  this  sort  are  not  so  common,  but  even  in  these  fields  the  pro- 
duction of  individual  wells  is  erratic.  The  high  flush  production 
with  rapid  decline  may  cause  serious  overestimation  of  reserves  if  a 
well  comes  in,  or  is  cleaned  out  in  the  last  month  of  the  taxable 
year. 

The  tables  submitted  herewith  have  been  compiled  from  records 
of  a  large  number  of  wells,  many  of  which  were  being  reworked 
from  time  to  time,  and  consequently,  represent  the  average  well. 
In  the  older  fields  where  the  gas  pressure  has  been  largely  ex- 
hausted and  many  of  the  sands  have  been  flooded,  only  records  of 
recent  years  have  been  used  in  the  compilation. 

Curves  are  not  included,  as  it  has  been  thought  best  to  get 
these  data  before  the  operators  at  once,  rather  than  to  wait  for 
plates  to  be  made.  If  it  is  felt  by  the  user  that  a  graphic  represen- 
tation is  necessary  or  desirable,  a  curve  can  be  constructed  in  a  few 
moments  from  the  figures  given  by  any  engineer.  It  should  be 
noted  also  that  future  production  is  not  based  upon  average  pro- 
duction for  taxable  year  as  in  the  "  Manual  for  the  Oil  and  Gas 
Industry,"  but  on  the  average  production  for  the  last  month  of  the 
taxable  year. 

Humble  Field. 

The  initial  production  of  the  pool  was  from  the  "  cap  rock." 
This  is  a  porous  formation,  which  contained  oil  under  high  pres- 


168 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY 


sures  and  the  early  wells  were  very  large  producers.  The  cap  rock 
is  now  flooded  and  is  not  a  factor  in  production. 

Numerous  irregular  lenses  of  oil  sands  are  found  above  and 
overlapping  the  cap  rock.  The  wells  range  from  600  to  1,800  feet 
in  depth,  and  ordinarily  do  not  go  to  water.  Th(  table  of  shallow 
sands  represents  the  production  from  these  wells. 

On  the  edges  of  the  salt  dome  at  a  depth  of  about  3,000  feet,  oil 
sands  occur  dipping  away  from  the  salt  dome.     These  give  high 

HUMBLE  (Shallow  Sands,  Less  than  2,000  Feet). 


Average 

Average 

Average 

Production 

per  Well 

per  Month 

Last  Four 

Months 

Taxable 

Estimated 
Average 
Future 

Production 
per  Well. 

Production 

per  Well 

per  Month 

Last  Four 

Months. 

Taxable 

Estimated 

Average 

Future 

Production 

per  Well. 

Production 

per  Well 

per  Month 

Last  Four 

Months 

Taxable 

Estimateed 

Average 

Future 

Production 

per  Well. 

Year. 

Year. 

Year. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

25 

0 

175 

2,100 

400 

6,500 

50 

260 

200 

2,500 

450 

7,700 

75 

550 

•     225 

2,800 

500 

8,900 

100 

900 

250 

3,300 

550 

10,200 

125 

1,260 

300 

4,300 

600 

11,000 

150 

1,700 

350 

5,200 

HUMBLE  (Deep  Wells,  over  2,000  Feet). 


Average 
Production 

per  Well 

Last  Month 

of  Taxable 

Year. 

Estimated 

Future 
Production. 

Average 
Production 

per  Well 

Last  Month 

of  Taxable 

Year. 

Estimated 

Future 
Production, 

Average 
Production 

per  Well 

Last  Month 

of  Taxable. 

Year. 

Estimated 

Future 
Production. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

100 

0 

600 

3,823 

1,800 

16,950 

110 

100 

650 

4,240 

2,000 

19,775 

125 

147 

700 

4,660 

2,500 

26,196 

150 

223 

750 

5,235 

3,000 

31,646 

200 

355 

800 

5,676 

3,500 

36,380 

250 

760 

850 

6,124 

4,000 

40.746 

300 

1,195 

900 

6,589 

5,000 

49,373 

350 

1,531 

1,000 

7,. 599 

7,500 

68,715 

400 

2,025 

1,200 

9,865 

10,000 

84,046 

450 

2,425 

1,400 

12,365 

15,000 

103,335 

500 

2,875 

1,600 

14,576 

20,000 

117,585 

550 

3,292 

F^ 


Ee; 


2u0,0O0 

180,000 

:::: 

Future  Production  per  Well,  in  Barrels 

~_           -/T 

■■■■ 

- - 1                          ^'^ 

-.t -^-""^ 

.ilJ|ML^M1^5Hli-^:          ■     j                1 

,   :    :di::::::::::::::::;;:::: 

I                j                           ^  ±±fc.- 

Oj     BO,00u\ 

5 

a 

40.000 

--ft ' — 

Tli:::::::::::::::::::::::::::::::::::::::: ::::::::::::: 

-     -;    '      1                  1 

::::;:; 

/ 

:  n  -  -         -           -            - .......     . . 

1, 

:           ::::::  ::::::::::::::::::::::::::::::::::::: 

-.0.000  50,000  60.000  70.000  80.000  90,000  100,000  110.000  720.000 

Aoeraqe  Monthly  Production  per  Well  during  Last  Month  of  Taxable  Year,  in  Barrels 


(To  face  page  169.) 


MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY 


169 


gas  pressure,  large  initial  production,  and  die  by  going  to  water. 
The  deep  sand  table  of  Humble  represents  production  from  these 
sands. 

Goose  Creek. 

Production  is  from  a  series  of  sands  or  lenses  of  sand  from  a 
depth  of  600  feet  to  3,600  feet,  the  large  production  starting  at 
about  2,200  feet.  There  are  apparently  three  zones  of  lenses. 
If  we  assume  that  there  is  a  deep-seated  salt  dome  at  Goose  Creek, 
the  sands  here  correspond  to  those  at  Humble  along  the  cap  rock. 
The  great  difference  is  that  the  wells  die  by  sanding  up  or  going 
to  water,  often  very  suddenly. 

GOOSE  CREEK 


Average 
Production 

per  Well 

Last  Month 

of  Taxable 

Year. 

Estimated 

Future 
Production. 

Average 
Production 

per  Well 

Last  Month 

of  Taxable 

Year. 

Estimated 

Future 
Production. 

Average 
Production 

per  Well 

Last  Month 

of  Taxable 

Year. 

Estimated 

Future 
Production. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

300 

0 

1,700 

7,400 

20,000 

54,400 

350 

460 

2,000 

9,260 

25,000 

62,000 

400 

730 

2,300 

11,260 

30,000 

68,200 

450 

1,010 

2,500 

12,800 

35,000 

74,400 

500 

1,230 

2,700 

14,330 

40,000 

80,200 

600 

1,590 

3,000 

16,400 

45,000 

85,500 

700 

1,900 

3,500 

19,640 

50,000 

92,000 

800 

2,250 

4,000 

22,560 

60,000 

104,000 

900 

2,730 

5,000 

27,200 

70,000 

115,500 

1,000 

3,330 

6,000 

31,000 

80,000 

127,500 

1,100 

3,630 

8,000 

37,500 

85,000 

133,000 

1,300 

4,730 

10,000 

31,000 

150,000 

167,000 

1,500 

6,030 

15,000 

47,000 

Saratoga. 

In  Saratoga  pool  the  sands  are  very  irregular  and  cannot  be 
correlated  from  well  to  well.  Apparently,  a  series  of  limestones, 
sands  and  clays  has  been  contorted  by  the  formation  of  a  salt 
dome.  Most  of  the  wells  eventually  go  to  water,  but  in  some  lenses 
of  sand  water  does  not  appear.     In  spite  of  the  fact  that  wells  are 


MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY 


169 


gas  pressure,  large  initial  production,  and  die  by  going  to  water. 
The  deep  sand  table  of  Humble  represents  production  from  these 
sands. 

Goose  Creek. 

Production  is  from  a  series  of  sands  or  lenses  of  sand  from  a 
depth  of  600  feet  to  3,600  feet,  the  large  production  starting  at 
about  2,200  feet.  There  are  apparently  three  zones  of  lenses. 
If  we  assume  that  there  is  a  deep-seated  salt  dome  at  Goose  Creek, 
the  sands  here  correspond  to  those  at  Humble  along  the  cap  rock. 
The  great  difference  is  that  the  wells  die  by  sanding  up  or  going 
to  water,  often  very  suddenly. 

GOOSE  CREEK 


Average 

Average 

Average 

Production 

per  Well 
Last  Month 
of  Taxable 

Estimated 

Future 
Production. 

Production 

per  Well 
Last  Month 
of  Taxable 

Estimated 

Future 
Production. 

Production 

per  Well 
Last  Month 
of  Taxable 

Estimated 

Future 
Production. 

Year. 

Year. 

Year. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

300 

0 

1,700 

7,400 

20,000 

54,400 

350 

460 

2,000 

9,260 

25,000 

62,000 

400 

730 

2,300 

11,260 

30,000 

68,200 

450 

1,010 

2,500 

12,800 

35,000 

74,400 

500 

1,230 

2,700 

14,330 

40,000 

80,200 

600 

1,590 

3,000 

16,400 

45,000 

85,500 

700 

1,900 

3,500 

19,640 

50,000 

92,000 

800 

2,250 

4,000 

22,560 

60,000 

104,000 

900 

2,730 

5,000 

27,200 

70,000 

115,500 

1,000 

3,330 

6,000 

31,000 

80,000 

127,500 

1,100 

3,630 

8,000 

37,500 

85,000 

133,000 

1,300 

4,730 

10,000 

31,000 

150,000 

167,000 

1,500 

6,030 

15,000 

47,000 

Saratoga. 

In  Saratoga  pool  the  sands  are  very  irregular  and  cannot  be 
correlated  from  well  to  well.  Apparently,  a  series  of  limestones, 
sands  and  clays  has  been  contorted  by  the  formation  of  a  salt 
dome.  Most  of  the  wells  eventually  go  to  water,  but  in  some  lenses 
of  sand  water  does  not  appear.     In  spite  of  the  fact  that  wells  are 


170 


MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY 


constantly  being  reworked,  the  decline  ov.  the  average  is  fairly 
regular,  and  some  wells  have  produced  since  1905. 

Two  tables  are  presented — one  for  the  Rio  Bravo  holdings 
where  the  wells  have  been  reasonably  spaced  and  the  other  for  the 
rest  of  the  pool,  where  town  lot  driUing  was  the  rule. 

SARATOGA,  RIO  BRAVO. 


Average 
Production 
per  Well 
During 
Taxable 
Year. 

Estimated 

Future 
Production. 

Average 
Production 
per  Well 
During 
Taxable 
Year. 

Estimated 
Future 
Future 

Average 
Production 
per  Well 
During 
Taxable 
Year. 

Estimated 

Future 
Production. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

500 

0 

3,000 

10,500 

10,000 

43,000 

585 

300 

3,500 

13,900 

12,000 

50,000 

800 

885 

4,000 

17,300 

15,000 

61,100 

1,100 

1,685 

5,000 

22,500 

17,500 

69,400 

1,250 

2,000 

6,000 

27,300 

20,000 

77,100 

1,500 

2,900 

7,000 

31,400 

22,500 

84,150 

2,000 

4,800 

8,000 

35,400 

25,000 

91,000 

2,500 

7,600 

9,000 

39,460 

26,000 

93,700 

SARATOGA  (All  Properties  Except  Rio  Bravo). 


Average 
Monthly 
Production 
per  Well 
Durii  g 
Taxable 
Year. 

Estimated 

Future 
Product  on. 

Average 
Monthly 
Production 
per  Well 
During 
Raxable 
Year. 

Estimated 

Future 
Production. 

Average 
Monthly 
Production 
per  Well 
During 
Taxable 
Year. 

Estimated 

Future 
Production. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

330 

0 

1,800 

2,280 

.       6,000 

9,500 

500 

150 

2,000 

2,750 

7,000 

11,290 

700 

330 

2,500 

4,080 

8,000 

12,900 

900 

580 

3,000 

4,910 

9,000 

15,000 

1,000 

710 

3,500 

5,740 

10,000 

17,550 

1,250 

1,030 

4,000 

6,580 

11,000 

21,350 

1,500 

1,600 

5,000 

8,080 

12,000 

27,130 

Sour  Lake. 


Conditions  are  similar  to  those  in  Saratoga.     Production  is  now 
from  sands  along  the  cap  rock  from  a  depth  of  500  to  1,500  feet. 


it 


VoP 


5,000 

;/  Producti 


1  i  1  1  I  H  1  1- 

44m4miiii!  . ^-.-. ----!---. .---;,--..,;-------------------------------^ 

le.ooo 

5-             ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::  :::::::::::^                         / 

»,o» 

.^     fc;:;;::;;;:;::::;:^:                   ;  iM:,,,:,:^!^    /            . 

..00 

-:::::::::::i: 

_^' 

■ttf    "                 1Y                                                          "'^ 

2,000 
8,000 

4.000 

/-^                                                                 ,iH±|:-:|::::::;;:;:;;::::ii::;:;:;q                      ^ 

^,mo  4.000  6,000  e.000  7.uu;  ::.uuO  9.000  10,000 

Average  Monthly  Production  per  Well  durimj  Taxable  Year,  in  Barrels 


(To  face  page  170.) 


,*»  ^ 

^  -*  ^ 

^  ■*• 

^  -^ 

^-^ 

^  •«• 

^  -"^ 

^^ 

**  "^ 

^  *^ 

«  eV    ^-'^ 

Cfl9,><^ 

j^^ 

_^' ,  ,1     ,  , 

t^" 

\                                qi 

, 

.. _,.   , ,. . „      „ 1 . 

60,000                 100,000                 120,000                 140,000                160,0 

Well  during  Taxable  Year,  in  Barrels 

(To  face  page  171.) 

80,000  100,000  120,000  140,000  160,000 

Well  during  Taxable  Year,  in  Barrels 

(To  face  page  171.) 


»-=- 



—                              -                      ^^^  r  '      1 

■    ..--^^^          ■                               '[ 

y^                                                                                          t 

-r-                 y 

/                                                                                                    ^t 

±__T-                  X 

;  : 

L  _                       -/- 

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■ :  : 

|5^;r;:'  ^ ,  /    :_: 

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"^il/ 

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if. 

■  r 

---m 

■ : 

;|„„-..-  ■ 

■   ■:■;■■, '-^ ^^^   -   ■   ^;;i^^^^ 

3n,m0  40,000  60.000  80.000  100.000  120.000  140,000  lOO.i 

Average  Production  per  Well  during  Taxable  Year,  in  Barrels 

(To  face  page  171.) 


MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY 


171 


SOUR  LAKE. 


Average 

Average 

Average 

Production 

per  Wrll 
Last  Month 
of  Taxable 

Estimated 

Future 
Production. 

Production 

per  Well 
Last  Month 
of  Taxable 

Estimated 

Future 
Production. 

Production 

per  Well 
Last  Month 
of  Taxable 

Estimated 

Future 
Production. 

Year. 

Year. 

Year. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

41 

50 

600 

10,000 

2,000 

27,840 

50 

185 

700 

11,750 

2,500 

20,700 

75 

765 

800 

13,550 

3,000 

32,900 

100 

1,600 

900 

15,280 

4,000 

37,200 

150 

2,800 

1,000 

16,870 

5,000 

41,000 

175 

3,200 

1,100 

17,870 

6,500 

46,300 

200 

3,750 

1,200 

20,100 

7,000 

47,000 

250 

4,500 

1,300 

21,400 

8,000 

51,500 

300 

5,300 

1,400 

22,600 

9,000 

56,000 

350 

6,000 

1,500 

23,900 

10,000 

61,000 

400 

6,800 

1,700 

25,540 

11,000 

66,000 

500 

8,375 

1,900 

27,240 

12,000 

71,000 

Batson. 

Produces  from  irregular  sands  as  in  Saratoga  and  Sour  Lake 
from  depths  of  200  to  1,500  feet.  Wells  constantly  reworked  but 
some  wells  producing  in  1908  are  still  productive  in  1918. 


BATSON. 


Average 
Production 

per  Well 

Last  Month 

of  Taxable 

Year. 

Estimated 

Future 
Production 

Average 
Production 

per  Well 

Last  Month 

of  Taxable 

Year. 

Estimated 

Future 
Production 

Average 
Production 

per  Well 

Last  Month 

of  Ta.\able 

Year. 

Estimated 

Future 
Production 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels 

Barrels. 

20 

0 

250 

7,680 

1,500 

23,000 

25 

40 

300 

9,180 

1,750 

24,300 

50 

380 

400 

12,260 

2,000 

25,400 

75 

890 

500 

13,960 

2,500 

27,000 

100 

1,630 

750 

17,000 

3,000 

27,900 

150 

3,760 

1,000 

19,400 

4,000 

29,100 

200 

5,830 

1,250 

20,400 

5,000 

30,700 

MANUAL  FOR  THE   OIL  AND   GAS  INDUSTRY  171 


SOUR  LAKE. 


Average 
Production 

per  Well 
Last  Month 
of  Taxable 

Estimated 

Future 
Production. 

Average 
Production 

per  Well 
Last  Month 
of  Taxable 

Estimated 

Future 
Production. 

Average 
Production 

per  Well 
Last  Month 
of  Taxable 

Estimated 

Future 
Production. 

Year. 

\  ear. 

Year. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

41 

50 

600 

10,000 

2,000 

27,840 

50 

185 

700 

11,750 

2,500 

20,700 

75 

765 

800 

13,550 

3,000 

32,900 

100 

1,600 

900 

15,280 

4,000 

37,200 

150 

2,800 

1,000 

16,870 

5,000 

41,000 

175 

3,200 

1,100 

17,870 

6,500 

46,300 

200 

3,750 

1,200 

20,100 

7,000 

47,000 

250 

4,500 

1,300 

21,400 

8,000 

51,500 

300 

5,300 

1,400 

22,600 

9,000 

56,000 

350 

6,000 

1,500 

23,900 

10,000 

61,000 

400 

6,800 

1,700 

25,540 

11,000 

66,000 

500 

8,375 

1,900 

27,240 

12,000 

71,000 

Batson. 

Produces  from  irregular  sands  as  in  Saratoga  and  Sour  Lake 
from  depths  of  200  to  1,500  feet.  Wells  constantly  reworked  but 
some  wells  producing  in  1908  are  still  productive  in  1918. 


BATSON. 


Average 
Production 

per  Well 

Last  Month 

of  Taxable 

Year. 

Estimated 

Future 
Production 

Average 
Production 

per  Well 

Last  Month 

of  Taxable 

Year. 

Estimated 

Future 
Production 

Average 
Production 

per  Weli 

Last  Month 

of  Taxable 

Year. 

Estimated 

Future 
Production 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels 

Barrels. 

20 

0 

250 

7,680 

1,500 

23,000 

25 

40 

300 

9,180 

1,750 

24,300 

50 

380 

400 

12,200 

2,000 

25,400 

75 

890 

500 

13,960 

2,500 

27,000 

100 

1,630 

750 

17,000 

3,000 

27,900 

150 

3.760 

1,000 

19,400 

4,000 

29,100 

200 

5,830 

1,250 

20,400 

5,000 

30,700 

172 


MANUAL  FOR  THE   OIL  AND   GAS   INDUSTRY 


Edgerly,  Vinton  and  Evangeline. 

These  are  typical  salt-dome  pools  which  have  been  ex- 
hausted except  for  the  stray  sands  and  an  occasional  pocket  of  oil 
in  the  cap  rock.  Production  is  extremely  erratic  and  the  deviation 
from  the  averages  given  in  the  table  is  large. 

EDGERLEY. 


Average 

Average 

Average 

Production 
per  Well 
During 
Taxable 

Estimated 

Future 
Production. 

Production 
per  Well 
During 
Taxable 

Estimated 

Future 
Production. 

Production 
per  Well 
During 
Taxable 

Estimated 

Future 
Production. 

Year. 

Year. 

Year. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

7,000 

4,000 

15,000 

56,800 

60,000 

140,100 

7,250 

6,000 

20,000 

65,300 

75,000 

151,300 

7,500 

10,000 

25,000 

74,000 

90,000 

160,950 

8,000 

20,120 

30,000 

87,200 

100,000 

166,500 

9,000 

34,700 

35,000 

99,500 

120,000 

177,100 

10,000 

44,000 

40,000 

110,800 

135,000 

185,200 

11,000 

48,240 

'50,000 

129,100 

150,000 

192,140 

VINTON. 


Average 
Production 

per  Well 

Last  Month 

of  Taxable 

Year. 

Estimated 

Future 
Production. 

Average 
Production 

per  Well 

Last  Month 

of  Taxable 

Year. 

Estimated 

Future 
Production. 

Average 

Production 

per  Well 

Last  Month 

of  Taxable 

Year. 

Estimated 

Future 
Production. 

Barrels 

250 
300 
400 
500 
600 
700 
800 
900 

Barrels. 

0 
250 
860 
1,780 
2,800 
4,025 
5,700 
7,000 

Barrels. 

1,000 
1,100 
1,200 
1,350 
1,500 
1,750 
2,000 

Barrels. 

8,500 
10,800 
12,400 
14,600 
17,400 
20,400 
23,900 

Barrels. 

2,250 
2,500 
2,750 
3,000 
3,500 
4,000 
4,500 

Barrels 

28,100 
32,650 
37,000 
40,600 
43,800 
47,600 
51,150 

For  Spindle  Top,  Anse  Le  Butte  and  Welch,  the  use  of  the 
Evangeline  table  is  suggested. 

For  Damon  Mound  and  Big  Hill,  Hull,  the  use  of  the  Goose 
Creek  table  is  suggested. 


4 


m 


5.000 

er  Well 


2,000  3,000 


Average  Production  per  Well  during  Last  Month  of  Taxable  Year,  in  Barrels 


(To  face  page  172.) 


MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY 


173 


For  Markham,  the  use  of  the  Humble  Shallow  sand  table  is 
suggested. 

Sufficient  data  for  the  compilation  of  a  table  are  lacking  in 
these  fields. 

In  any  case  where  the  production  for  one  w^ell  per  month  is 
above  that  given  in  the  table,  use  the  Goose  Creek  Table. 

EVANGELINE. 


Average 

Average 

Average 

Production 

per  Well 
Last  Month 
of  Taxable 

Estimated 

Future 
Production. 

Production 

per  Well 
Last  Month 
of  Taxable 

Estimated 

Future 
Production. 

Production 

per  Well 
Last  Month 
of  Taxable 

Estimated 

Future 
Production. 

Year. 

Year. 

Year. 

Barrels.    , 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

160 

0 

700 

10,020 

2,000 

31,500 

200 

340 

800 

12,900 

2,500 

40,000 

250 

980 

900 

13,900 

3,000 

47,000 

300 

1,400 

1,000 

15,900 

4,000 

56,200 

350 

2,400 

1,100 

17,580 

5,000 

62,100 

400 

3,200 

1,200 

19,000 

6,000 

67,100 

450 

4,370 

1,300 

21,080 

7,000 

71,100 

500 

5,630 

1,400 

22,380 

8,000 

74,600 

550 

6,570 

1,500 

25,200 

9,000 

77,100 

600 

7,700 

1,750 

27,700 

10,000 

78,770 

650 

9,930 

MEXICAN  OIL  FIELDS. 

General  features. — The  known  oil  fields  of  Mexico  are  included 
within  two  great  regions,  both  of  which  are  segments  of  the  Gulf 
Coastal  Plane,  Tampico-Tuxpam,  and  Tehuantepec-Tabasco 
regions.  They  cover  approximately  20,000  to  30,000  square  miles 
and  include  some  20  local  fields.  A  very  rough  estimate  places  the 
proved  area  in  the  two  regions  at  25  square  miles,  the  prospective 
area  at  500  to  1,000  square  miles.  Inasmuch  as  less  than  1,000 
wells  have  been  drilled  for  oil  in  the  entire  Republic  up  to  the  pres- 
ent time,  and  as  a  great  bulk  of  the  oil  has  come  from  two  wells,  it 
would  be  rash  indeed  to  give  too  much  weight  to  estimates  of  unit 
areas. 

The  principal  oil-yielding  rocks  are  limestones  or  limy  shales  of 
Cretaceous  or  Eocene  age.  Some  oil  is  found  in  the  later  Tertiaries 
in  the  southern  region.     Fields  are  generally  anticlinal  in  struc- 


MANUAL   FOR  THE   OIL  AND   GAS   INDUSTRY 


173 


For  Markham,  the  use  of  the  Humble  Shallow  sand  table  is 
suggested. 

Sufficient  data  for  the  compilation  of  a  table  are  lacking  in 
these  fields. 

In  any  case  where  the  production  for  one  w^ell  per  month  is 
above  that  given  in  the  table,  use  the  Goose  Creek  Table. 

EVANGELINE. 


Average 

Production 

•     per  Well 

Last  Month 

of  Taxable 

Year. 

Estimated 

Future 
Production. 

Average 
Production 

per  Well 

Last  Month 

of  Taxable 

Year. 

Estimated 

Future 
Production. 

Average 
Production 

per  Well 

Last  Month 

of  Taxable 

Year. 

Estimated 

Future 
Production. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

Barrels. 

160 

0 

700 

10,020 

2,000 

31,500 

200 

340 

800 

12,900 

2,500 

40,000 

250 

980 

900 

13,900 

3,000 

47,000 

300 

1,400 

1,000 

15,900 

4,000 

56,200 

350 

2,400 

1,100 

17,580 

5,000 

62,100 

400 

3,200 

1,200 

19,000 

6,000 

67,100 

450 

4,370 

1,300 

21,080 

7,000 

71,100 

500 

5,630 

1,400 

22,380 

8,000 

74,600 

550 

6,570 

1,500 

25,200 

9,000 

77,100 

600 

7,700 

1,750 

27,700 

10,000 

78,770 

650 

9,930 

MEXICAN  OIL  FIELDS. 

General  features. — The  known  oil  fields  of  Mexico  are  included 
within  two  great  regions,  both  of  which  are  segments  of  the  Gulf 
Coastal  Plane,  Tampico-Tuxpam,  and  Tehuantepec-Tabasco 
regions.  They  cover  approximately  20,000  to  30,000  square  miles 
and  include  some  20  local  fields.  A  very  rough  estimate  places  the 
proved  area  in  the  two  regions  at  25  square  miles,  the  prospective 
area  at  500  to  1,000  square  miles.  Inasmuch  as  less  than  1,000 
wells  have  been  drilled  for  oil  in  the  entire  Republic  up  to  the  pres- 
ent time,  and  as  a  great  bulk  of  the  oil  has  come  from  two  wells,  it 
would  be  rash  indeed  to  give  too  much  weight  to  estimates  of  unit 
areas. 

The  principal  oil-yielding  rocks  are  limestones  or  limy  shales  of 
Cretaceous  or  Eocene  age.  Some  oil  is  found  in  the  later  Tertiaries 
in  the  southern  region.     Fields  are  generally  anticlinal  in  struc- 


174  MANUAL   FOR   THE   OIL  AND   GAS   INDUSTRY 

ture,  but  in  some  instances  the  structure  has  not  yet  been  deter- 
mined. The  underground  reservoirs  are  associated  with  volcanic 
intrusions. 

The  oldest  development  of  importance  began  in  1906,  but  the 
larger  wells  were  not  developed  until  four  or  five  years  later.  The 
wells  average  in  depth  2,500  feet  and  in  production  from  50  to  over 
100,000  barrels  daily.  The  oils  range  in  gravity  from  10°  to  14° 
Baume  in  the  Panuco  field  and  from  15°  to  29°  Baume  in  the  others, 
the  average  for  the  most  productive  field,  the  Tepetate,  being 
about  21°  or  .927  specific  gravity.  The  oil  is  usually  accompanied 
by  large  quantities  of  wet  gas.  Estimates  of  from  4,000,000  to 
12,000,000  cubic  feet  of  gas  daily  being  yielded  by  some  of  the  wells. 
Both  the  rotary  hydraulic  and  standard  cable  systems  of  drilling 
are  used. 

The  first  and  most  general  use  for  the  Mexican  crude  oil  aside 
for  supplying  oil  for  refining  for  local  trade  has  been  as  fuel  oil. 
Most  of  the  oil  is  exported  to  the  United  States  or  other  countries. 

Statement  regarding  depletion  allowanceSc — The  depletion  of 
the  oil  reserves  in  the  Mexican  fields  is  an  unquestionable  fact,  but 
owing  to  the  large  volume  of  oil  produced  by  the  commercially 
successful  wells  and  to  restricted  transportation  facilities,  it  is  at 
present  and  has  been  during  past  years,  impossible  to  show  the 
actual  diminution  of  flow.  In  other  words,  the  existing  pipe-line 
systems  in  connection  with  the  available  tank  steamer  fleets  can 
not  transport  the  oil  out  of  Mexico  as  fast  as  the  wells  are  capable 
of  producing  it.  Obviously,  at  some  future  time  the  diminution  in 
the  oil  flow  or  the  increase  in  transportation  or  storage  capacities 
will  reach  a  point  where  the  decline  in  production  of  the  large  wells 
is  actually  shown,  but  for  present  purposes  in  estimating  allow- 
ances for  depletion  there  is  little  or  nothing  in  the  shape  of  pro- 
duction decline  records  on  which  to  base  an  estimate  of  the  prob- 
able future  production  of  the  large  Mexican  oil  wells  and  one  is 
therefore  confronted  at  the  outset  by  an  almost  complete  lack  of 
records  essential  in  computing  the  fundamental  unknown  factors 
in  the  problem.  Were  one  to  compute  at  present  the  depletion  of 
the  large  Mexican  oil  wells,  which  yield  the  bulk  of  the  marketed 
oil,  on  the  basis  of  the  diminution  of  flow,  he  would  arrive  in  most 
cases  at  the  incongruous  conclusion  that  no  depletion  takes  place 
even  though  the  well  might  be  producing  millions  of  barrels  per 
year. 


^^ 


^ 


C/ased  or  f?ock   Pressure   Dec/ine. 

"IG.  13.— REPRESENTATIVE  CLOSED    PRESSURE  DECLINE  CURVES  FOR  GAS  V/ELLS  AND   POOLS   IN  VARIOUS  PARTS  OF  THE  UNITED  STATES.     SEE  PAGES  31 


MANUAL  FOR  THE  OIL  AND  GAS  INDUSTRY  175 

With  this  in  mind  we  must  be  sure  at  the  outset  that  (any 
estimates  of  probable  depletion  of  the  content  of  Alexican  oil  land, 
being  based  almost  entirely  on  more  or  less  plausible  conjectures) 
any  estimates  of  depletion  of  necessity  presuppose  a  previous 
knowledge  of  the  probable  amount  of  oil  underground  in  any  par- 
ticular property,  and  although  here  again  we  are  confronted  with 
the  lack  of  sufficient  data  on  which  to  base  accurate  conclusions, 
enough  evidence  is  available  to  enable  one  in  most  instances  to 
roughly  approximate  the  oil  reserves.  The  greatest  elasticity, 
however,  will  be  given  to  the  taxpayer  in  devising  methods  of  esti- 
mating reserves  so  that  proper  allowances  may  be  made  in  prac- 
tically every  individual  case  that  comes  up  for  consideration,  in 
order  not  to  work  undue  hardship  on  the  operators  by  arbitrary 
interpretations. 

The  producing  life  of  gushers  yielding  thousands  of  barrels  of 
oil  daily,  obviously  is  controlled  by  different  factors  from  those  gov- 
erning the  small  pumping  wells  perhaps  adjoining  a  big  producer, 
and  these  and  many  other  factors  affecting  the  problem  are  ren- 
dered doubly  obscure  by  the  indefinite  length  of  time  throughout 
which  the  effect  of  the  restricted  land  and  marine  transportation 
facilities  will  be  felt. 

In  view  of  the  foregoing,  the  task  of  estimating  the  amount  of  . 
oil  in  any  particular  property  will  be  left  largely  to  the  taxpayer 
controlling  the  tract  and  the  Internal  Revenue  Bureau  will  for  the 
present  confine  itself  to  a  critical  analysis  of  the  various  estimates 
before  issuing  any  average  curves  or  approximate  bench  marks  on 
which  to  base  the  computation  of  depletion  allowances. 

In  setting  up  values  as  of  March  1,  1913,  or  for  any  subsequent 
date,  for  properties  in  Mexico  or  any  other  foreign  country,  or  in 
computing  depletion  and  depreciation  allowances,  the  same  evi- 
dence will  be  required  by  the  Internal  Revenue  Bureau  as  that  for 
properties  in  the  United  States,  and  in  filing  returns  the  taxpayer 
must  in  all  cases  append  complete  evidence  supporting  all  claims. 

GAS  FIELDS  OF  THE  UNITED  STATES. 

Representative  decline  curves. — On  Fig.  13  are  shown  selected 
closed-pressure  decline  curves  for  wells,  pools,  and  sands  in  various 
parts  of  the  United  States.  It  will  be  observed  first,  that  the  rate 
of  decline  varies  between  wide  limits;    second,  that  there  are 


i 


MANUAL  FOR  THE  OIL  AND   GAS  INDUSTRY  175 

With  this  in  mind  we  must  be  sure  at  the  outset  that  (any 
estimates  of  probable  depletion  of  the  content  of  Mexican  oil  land, 
being  based  almost  entirely  on  more  or  less  plausible  conjectures) 
any  estimates  of  depletion  of  necessity  presuppose  a  previous 
knowledge  of  the  probable  amount  of  oil  underground  in  any  par- 
ticular property,  and  although  here  again  we  are  confronted  with 
the  lack  of  sufficient  data  on  which  to  base  accurate  conclusions, 
enough  evidence  is  available  to  enable  one  in  most  instances  to 
roughly  approximate  the  oil  reserves.  The  greatest  elasticity, 
however,  will  be  given  to  the  taxpayer  in  devising  methods  of  esti- 
mating reserves  so  that  proper  allowances  may  be  made  in  prac- 
tically every  individual  case  that  comes  up  for  consideration,  in 
order  not  to  work  undue  hardship  on  the  operators  by  arbitrary 
interpretations. 

The  producing  life  of  gushers  yielding  thousands  of  barrels  of 
oil  daily,  obviously  is  controlled  by  different  factors  from  those  gov- 
erning the  small  pumping  wells  perhaps  adjoining  a  big  producer, 
and  these  and  many  other  factors  affecting  the  problem  are  ren- 
dered doubly  obscure  by  the  indefinite  length  of  time  throughout 
wliich  the  effect  of  the  restricted  land  and  marine  transportation 
facilities  will  be  felt. 

In  view  of  the  foregoing,  the  task  of  estimating  the  amount  of  . 
oil  in  any  particular  property  will  be  left  largely  to  the  taxpayer 
controlling  the  tract  and  the  Internal  Revenue  Bureau  will  for  the 
present  confine  itself  to  a  critical  analysis  of  the  various  estimates 
before  issuing  any  average  curves  or  approximate  bench  marks  on 
which  to  base  the  computation  of  depletion  allowances. 

In  setting  up  values  as  of  March  1,  1913,  or  for  any  subsequent 
date,  for  properties  in  Mexico  or  any  other  foreign  country,  or  in 
computing  depletion  and  depreciation  allowances,  the  same  evi- 
dence will  be  required  by  the  Internal  Revenue  Bureau  as  that  for 
properties  in  the  United  States,  and  in  filing  returns  the  taxpayer 
must  in  all  cases  append  complete  evidence  supporting  all  claims. 

GAS  FIELDS  OF  THE  UNITED  STATES. 

Representative  decline  curves. — On  Fig.  13  are  shown  selected 
closed-pressure  decline  curves  for  wells,  pools,  and  sands  in  various 
parts  of  the  United  States.  It  will  be  observed  first,  that  the  rate 
of  decline  varies  between  wide  limits;    second,  that  there  are 


176  MANUAL  FOR  THE   OIL  AND  GAS  INDUSTRY 

occasional  temporary  rises  in  pressure;  third,  that  a  well  or  pool 
may  on  the  one  hand  "  drown  out  "  abruptly,  the  pressure  declining 
from  perhaps  several  hundred  pounds  to  zero  in  a  few  days  as  the 
well  fills  with  water,  or  at  the  other  extreme  a  well  or  pool  such  as 
the  low-pressure  wells  of  Indiana  or  certain  high-pressure  wells  of 
Pennsylvania  may  decline  very  slowly  over  a  period  of  many  years. 


INDEX 


PAGE 

Abandonment  of  wells,  pressure  at 36 

Accounts  required,  depletion 39 

Adair  district,  Oklahoma 124 

Adams  County,  Ind 112 

Allegany  County,  N.  Y 94 

Allegheny  County,  Pa 97 

Allen  County,  Ohio 112 

Allocation  between  depletion  and  depreciation 16,  17 

Allowance: 

For  depletion 6,  19,  20,  31,  32,  SO 

For  depreciation 6,  13,  19 

Property  paid  in  and  written  off,  etc 6 

Reserve  for  depletion 6 

Reserve  for  depreciation 6 

Allowable  deductions,  cost  of  development 9 

Amended  returns,  when  required 17 

Amortization: 

Definition  of 18 

Period 18 

Property  cost,  returnable  through 18 

Redetermination  of,  requirements  for 18 

Appalachian  region: 

Future  production  curves 99 

General  outline 92 

Appraisal,  curve  method 86 

Augusta  district,  Kansas,  estimated  future  production 121 

Avant-Ramona  district,  Oklahoma,  estimated  future  production 126 

Average  decline  curve 81 

Bartlesville-Dewey,  Hogshooter  district,  Oklahoma,  estimated  future  pro- 
duction   122,  123 

Basis : 

Of  depletion  deduction 21 

Of  discovery,  revaluation  of  properties  on 43,  44 

For  deductions 5 

Bath  County,  Ky 104 

177 


178  INDEX 

PAGE 

Belmont  County,  Ohio 101 

Belridge  field,  California 154 

Berea  sand,  Ohio 101 

Berea  sand,  West  Virginia 100 

Bird  Creek-Skiatook  district,  Oklahoma 127,  128 

Birds  Flatrock  pool,  Illinois 114 

Blackford  County,  Ind 112 

Blackwell  district,  Oklahoma 133 

Bona  fide  sale: 

of  mines,  etc 3,  4 

Schedule  for  proof  of 62 

Boyle's  law 31 

Bradford  sand,  Pennsylvania 95 

Buena  Vista  Hills,  California 152 

Buildings,  depreciation  of 71 

Burkburnett  field,  Texas 136 

Butler  County,  Pa 91 

Caddo  oil  field 137 

California  oil  fields 146 

Capital,  charges  to 46 

Capital  recoverable  through  depletion  allowance 20 

Capital  sum,  illustration  of 7 

Capital  sum  and  invested  capital,  depletion  allowance,  illustration  of 

effect  on 20 

Capital  sum  returnable  through  depreciation  allowance 15 

Carlyle  pool,  Illinois 113 

Casing-head  gas  contracts,  tangible  assets 46 

Cattaraugus  County,  N.  Y 94 

Charges  to — 

Depletion 90 

Expenses 46 

Claims,  five-year  limit  for  filing      12 

Clark  County,  111 113 

Cleveland  district,  Oklahoma 126 

Clinton  County,  111 113 

Clinton  sand,  Hocking  and  Wayne  Counties,  Ohio 103 

Closed-pressure  method : 

Corrections  and  refinements 32 

For  estimating  depletion 32 

of  gauging 34 

Readings  to  be  recorded 35 

Season  for  testing  wells 35 

Significant  details 37 

Closing  account,  depreciation 16 

Coalinga  East  Side  field,  California 158 

Coalinga  West  Side  field,  California 157 


INDEX  179 

PAOE 

Combined  holdings  of — 

Gas  properties,  depletion  allowance,  computation  of 39 

Oil  properties,  depletion  allowance,  conii)utation  of 38 

Computations  of  allowance  for  depletion  of — 

Gas  wells 29 

Oil  wells 27 

Computation  of  depreciation  allowances 15 

Computation  of: 

Surtax 2 

Table  of 2 

Concrete  example,  depletion  of  gas 35 

Corrections  and  refinements,  closed  pressure  method 32 

Corsicana  field,  Texas 134 

Cost  of  deposits,  determination  of 23 

Cost  of  property  as  of  any  specified  date,  schedule  for  ascertaining 47 

Crawford  County,  111 114 

Cumberland  County,  111 114 

Curve : 

Average  decline 81 

Decline,  symmetrical  character 82 

Production,  definition  of 81 

Curves  and  tables,  estimated  future  production 92 

Cushing  district,  Oklahoma 129 

Damages  paid,  deductible 12 

Decline  curves 82 

Decline  in  open  flow  capacity,  gas 30 

Deductible  as  expenses,  development  cost,  or  charged  to  capital 10 

Deductible,  damages  paid 12 

Deduction  of  charges,  time  for,  on  books  required 11 

Deductions  allowable: 

Bonuses  to  employees 11 

Depletion 18 

Depreciation 13 

For  personal  services 11 

Individuals 11 

Return  on  accrued  basis 11 

Definitions : 

Amortization 18 

Depletion 18 

Depreciation 13 

Expenses 10 

Fair  market  value 24 

Gross  income 5 

Net  income 5 

Physical  property 9 

Proven  oil  land 91 


180  INDEX 

PAoa 

Definitions — Continued. 

Unit  cost 28 

Dehydrators,  depreciation  of 69 

Dennison  pool,  Illinois 115 

Depletion : 

Account  required 39 

Account  separate  from  depreciation 40 

Allowance  for 6 

Capital  recoverable  through,  owner 20 

Computation  of — 

For  combined  holdings  of  gas  properties 39 

For  combined  holdings  of  oil  properties 38 

Concrete  example  of 31 

Gas  formula 36 

Illustration  of  effect  on  capital  sum  and  invested  capital 21 

Mexican  fields 174 

Apportionment  among  various  sands 34 

Apportionment  of  deductions  between  lessor  and  lessee .  22,  23,  24,  28,  29 

Basis  of  deductions 19 

For  performance  record 30 

Charges  corrected 90 

Definition  of 18 

For  years  prior  to  1916 17 

Gas,  additional  indications  of 31 

Lessee  entitled  to 20 

Of  gas  wells,  computations  of  allowance  for 29,  30 

Of  gas,  concrete  example 35 

Of  oil  wells,  computation  of  allowance  for 29 

Of  oil  or  gas  claimed,  detailed  statement  to  be  attached 41 

Of  oil  and  gas  wells 19 

Past  years  not  allowed 47 

Reserve  distribution  from 40 

Reserve  for 6 

Depreciable  property 14 

Depreciation : 

Accounts  required 39 

Allowance 6,  13 

Capital  sum  returnable  through 15 

Computation  of 15 

Deductions  on  books  required 16 

Reserve 16 

Buildings 17 

Closing  account 16 

Computation  of 15 

Creditable  to  reserve 13 

Definition  of 13 

Dehydrators 69 


INDEX  181 

PAOB 

Depreciation — Continued. 

Drilling  equipment 68 

Electric  equipment 70 

For  years  prior  to  1916 17 

Improvements 17 

Intangible  property 14 

Machine  shop 71 

Personal  effects  not  deductible 15 

Pipe  lines 71,  72 

Rates,  gas  pipe  lines 72 

Refineries 73 

Reserve  distribution  from 40 

Schedule 62 

Table,  rate 78 

Tank  cars 72,  76 

Tanks 70 

Tools 70 

Transportation  equipment 70 

Water  plants 70 

Well  equipment 68 , 

De  Soto  field,  Louisiana 140 

Details  concerning  mai)s 42 

Determination  of — - 

Cost  of  deposits 23 

Quantity  of  oil 25 

Unit  cost 27 

Value — 

Direct  methods 56 

Fair  market 23 

Indirect  methods 58 

Development  costs: 

Deductible  as  expense  or  chargeable  to  cajiital 9 

Inclusions,  allowable  deductions 9,  10 

Direct  methods  of  determining  value 56 

Discovery : 

Proof  of 43 

Schedule  for  proving  principal  valae,  demonstrated 65 

Distributing  stations 76 

Dividend,  liquidating 40 

Dorseyville  pool,  Pennsylvania 97 

Drilling  e(juipmcnt,  depreciation  of 68 

Economic  limit  of  production 81 

Eldorado  district,  Kansas 120 

Electra  field,  Texas 135 

Electric  eriuipnumt,  dci)reciation 70 

Elk  Basin  field,  Wyoming , 145 


182  INDEX 

PAGE 

Equal  expectations,  law  of 88 

Equipment  {see  also  physical  property) 9 

Estill  County,  Ky 106 

Estimate  required  of  recoverable  oil 26,  27 

Estimated  future  recovery 85-91 

Estimating  depletion,  closed-pressure  method  for  gas 31 

Excess-profits  tax  and  war  profits 4 

Expenses : 

Charges  to 46 

Definition  of 10 

Improvements  and  betterments  not  deductible  as 10 

Repairs  and  replacements 10 

Fair  market  value,  definition  of 25 

Fellows  area,  Midwayfield,  Calif 149 

Fictitious  price  not  permissible 23 

Fifth  sand,  Pennsylvania 97 

Filling  stations 75 

Five-year  limit  for  filing  claims 12 

Floyd  County,  Ky 105 

Foreword iii,  iv 

Formula,  depletion  allowance,  gas 36 

Fullerton  oil  field,  La  Habra  group,  California 164 

Future  production,  method  of  estimating 80 

Future  production  curves: 

Appalachian  district 99 

California  oil  fields    149,  166 

Illinois-Indiana  field 113 

Lima-Indiana  field 110 

Mid-Continent  district 122,  133 

Northern  Louisiana  fields 136 

Rocky  Mountain  fields 141 

Future  production  curves  and  tables 92 

Garber  district,  Oklahoma 132 

Garfield  County,  Okla 132 

Gas: 

Amount  of  concrete  example 31 

Decline  curves 175 

Decline  in  open-flow  capacity 30 

Natural 76 

Pipe  line,  depreciation  rate 71 

Pore-space  method  for  estimating  supply  of 30 

Pressure,  observation  of 31 

Gasoline  plants,  natural  gas 77 

Gibson  County,  Ind 116 

Glenn  ]nm\,  ( )klahoma 128 


INDEX  183 

PAGE 

Gore  pool,  Ohio 103 

Gordon  sand  in  Wetzel  County,  W.  Va 102 

Grant  County,  Ind 113 

Grass  Creek,  Wyo 144 

Gratuities  not  deductible 11 

Gross  income  definition  of 5 

Hancock  County,  Ohio Ill 

Harrison  County,  W.  Va 99 

Healdton  district,  Oklahoma 132 

Hocking  County,  Ohio 103 

Hot  Springs  County,  Wyo 144 

Hundred  Foot  sand,  Pennsylvania 96 

Huntington  County,  lad 113 

Illinois-Indiana  field  future  production  curve 107 

Improvements  and  betterments  not  deductible  as  expense 10 

Improvements,  depreciation  of 17 

Indeterminate  losses 13 

Indications  of  depletion,  gas 31 

Indirect  methods  of  determining  value 58 

Individual  normal  income  tax  of 1 

Individual,  surtax  of 1 

Insurance  companies,  deductions  special 5 

Intangible  property,  depreciation  of 14 

Invested  capital 7 

Irvine  pool,  Kentucky,  estimated  future  production 106 

Jefferson  County,  Ohio 101 

Keener  sand,  Ohio 102 

Kirkwood  pool,  Illinois 115 

Law  of  averages 87 

Law  of  equal  expectations 88 

Lawrence  County,  111 115 

Lease,  valuation  of  fee  under 25 

Lessee  and  lessor,  apportionment  of  deductions  between 22 

Lessee: 

Capital  recoverable  through  depletion  allowance 20 

Entitled  to  depletion 20 

Lima-Indiana  district 94 

Lima-Indiana  field,  future  production  curves 107 

Limit  of  production,  economic 81 

Limits  on  surtax  and  war  excess-profits  tax  in  case  of  sale 3 

Lincoln  County,  W.  Va 100 

Liquidating  dividend 40 

Losses  deductible 12 


184  INDEX 

PAGE 

Losses : 

Determinate 13 

Not  deductible 13 

Lost  Hills  field,  California,  estimated  future  production 155 

Lucas  County,  Ohio,  estimated  future  production Ill 

Machine  shop,  depreciation  of 71 

Maps: 

Details  concerning 42 

To  be  submitted 42 

Maricopa  Flat  area.  Sunset  oil  field,  California 151 

Marion  County,  Tex 139 

Marion  County,  111 113 

McDonald  pool,  Pennsjdvania 97 

McDonough  County,  111 115 

McKean  County,  Pa 94 

McKittrick  field,  California 153 

Method,  appraisal  curve 86 

Method  of — 

Amorization 18 

Computing  depletion,  gas 30 

Estimating  future  production 83,  85 

Estimating  recoverable  oil  reserves 26,  83 

Gauging  gas,  closed  pressure 31 

Mercer  County,  Ohio 112 

Mexican  fields,  allowances  for 174 

Mexican  oil  fields 173 

Storage  capacities 174 

Transportation  facilities 174 

Mid-Continent  district,  future  production  curves 117 

Midway-Sunset  field,  California 148 

Monroe  County,  Ohio 101,  102 

Mooringsport  pool,  Louisiana 139 

Muskogee-Boynton  district,  Oklahoma 130 

Natural  gas 76 

Gasoline  plants 77 

Unit  cost 32 

Neodesha  district,  Kansas 121, 122 

Net  income,  definition 5 

New  Straitsville  pool,  Ohio 103 

Normal  income  tax  of  individual 1 

Northern  Louisiana  fields,  future  production  curves 136 

Nowata  district,  Oklahoma 123 

Oil  and  gas  wells,  depletion  of 18 

Okmulgee  district,  Oklahoma 131 


INDEX  185 

PAGE 

Olinda  field,  California 165 

Osage  County,  Okla 125 

Ottawa  County,  Ohio Ill 

Performance  record,  basis  for  gas  depletion 30 

Period,  amortization 18 

Perry  County,  Ohio 103 

Personal  effects,  depreciation  not  deductible 14 

Personal  services,  compensation  for 11 

Physical  property,  definition  of 9 

Pike  County,  Ind 116 

Pine  Island  pool,  Louisiana 130 

Pipe  lines,  depreciation  of 71,  72 

Plymouth  pool,  Illinois 115 

Pore-space  method  for  estimating  supply  of  gas 30 

Pressure  at  abandonment  of  wells 36 

Pressure,  observation  of  gas 31 

Production  curves,  definition  of 81 

Production  curves,  plotted 84 

Production,  estimates  of 148 

Production  oil  zone 147 

Proof  required  in  case  of  sale  of  mineral  deposits 4 

Property,  cost  of,  allowable  deductions 9 

Property,  cost  of,  inclusions 9 

Property  cost  returnable  through  amortization 18 

Property,  depreciable 14 

Property,  depreciation  of  intangible 14 

Property,  nondepreciable 15 

Property  paid  in  and  written  off: 

Reserve  for  depletion 6,  7 

Reserve  for  depreciation 6,  7 

Proven  oil  land,  definition  of 91 

Quantity  of  oil,  determination  of 25 

Readings,  closed-pressure,  significant  details 38 

To  be  recorded 37 

Recoverable  oil,  estimate  required 26 

Recoverable  oil  reserves,  methods  of  estimating 26,  80,  83 

Redetermination  of  amortization 18 

Red  River  field,  Louisiana 139,  140 

Refineries,  depreciation  of 73,  74 

Repairs  and  replacements  charged  as  exjjense 10 

Requirements  for  amortization 18 

Reserve: 

Distribution  from  depreciation 40 

Depreciation  creditable  to 13 


186  INDEX 

PAGE 

Return  on  accrued  basis,  deductions 11 

Revaluation  of  properties  on  basis  of  discovery 43,  44 

Revaluation  of  property,  not  permissible 25 

Revaluation  of  properties,  ruling  on 43 

Revaluation  within  30  days  of  discovery,  allowable 19 

Roane  County,  W.  Va 99 

Robinson  pool,  Illinois 114 

Rocky  Mountain  fields,  future  production  curves 141 

Sale,  limits  on  surtax  and  war-excess  profits  tax  in  case  of 3 

Sale  of  capital  assets,  schedule  for  computation  of  profits  or  loss  from ...  64 

Mineral  deposits,  surtax  on 3 

Sale,  schedule  for  proof  of 62 

Sale  of  mineral  deposits,  proof  required  in  case  of 4 

Sale  of  mines,  etc.,  bona  fide 3,  4 

Sales  or  marketing  equipment 75 

Salt  Creek  field,  Wyoming 143 

Salt  Creek  field,  first  Wall  Creek  sand 144 

Salt  Lake  field,  California 161 

Sandoval  pool,  Illinois 113 

Sandusky  County,  Ohio Ill 

San  Joaquin  Valley,  Calif 146 

Santa  Maria  field,  California.    159 

Schedule  for  ascertaining  cost  of  property 47 

Computation  of  profit  or  loss  from  sale  of  capital  assets 64 

Depletion 61 

Depreciation 62 

Proof  of  bona  fide  sale 62 

Proving  principal  value  demonstrated  by  discovery 65 

Proof  of  discovery 59 

Valuation  of  property 53 

Season  of  testing  wells,  closed  pressure 35 

Seneca  County,  Ohio Ill 

Shinnston  pool.  West  Virginia 99 

Siggins  pool,  Illinois 114 

Speedily  sand,  Pennsylvania 95 

St.  Marys  pool,  Ohio 102 

Statement  to  be  attached,  depletion  of  oil  or  gas  claimed 41 

Sullivan  pool,  Indiana 116 

Surplus,  allowance  for — 

Depletion 6,  7 

Depreciation 6,  7 

Surplus  and  undivided  profits 6,  7 

Surtax : 

Computation  of 2 

Table  of 2 


INDEX  187 

PAGE 

Surtax — Continued. 

On  sale  of  mineral  deposits,  limits  of 3 

Of  individual 1 

Table: 

Depreciation  rates,  marketing  equipment 75 

Estimated  future  production: 

Adair  district,  Oklahoma 125 

Adams  County,  Ind 112 

Allen  County,  Ohio 112 

Augusta  district,  Kansas 121 

Avant-Ramona  district,  Oklahoma 126 

Bartlesville-Dewey,  Hosghooter  district,  Oklahoma 123 

Batson 171 

Belridge  field,  California 155 

Berea  sand,  West  Virginia  and  Ohio 101 

Big  Injun  sand.  West  Virginia '. 100 

Bird  Creek-Skiatook  district,  Oklahoma 127 

Birds-Flatrock  pool,  Illinois 114 

Blackford  County,  Ind 112 

Blackwell  district,  Oklahoma 133 

Bradford  sand,  Pennsylvania 95 

Buena  Vista  hills,  California 153 

Burkburnett  field,  Texas 136 

Carlyle  pool,  Illinois 113 

Clark  County,  111 113 

Cleveland  district,  Oklahoma 127 

Clinton  County,  111 113 

CUnton  sand,  Hocking  and  Wayne  Counties,  Ohio 104 

Coalinga,  East  Side  field,  California 158 

Coalinga,  West  Side  field,  California 157 

Corsicana  field,  Texas 134 

Crawford  County,  111 114 

Cumberland  County,  111 114 

Gushing  district,  Oklahoma 129 

Dennison  pool,  Illinois 115 

De  Soto  field,  Louisiana 140 

Dorseyville  pool,  Pennsylvania 97 

Edgcrly 172 

Eldorado  district,  Kansas 120 

Electra  field,  Texas 135 

Elk  Basin  field,  Wyoming 145 

Evangeline 173 

Fellows  area,  California 150 

Fifth  sand,  Pennsylvania 97 

Floyd  County,  Ky 105 

Fullerton  oil  field,  La  Habra  group 165 


188  INDEX 

PA08 

Table — Continued . 

Estimated  future  production — Continued. 

Garber  district,  Oklahoma 132 

Gibson  County,  Ind 116 

Glenn  pool,  Oklahoma 128 

Goose  Creek 169 

Gordon  sand  in  Wetzel  County,  W.  Va 101 

Gordon  sand  in  Greene  County,  Pa 98 

Gordon  sand  in  Allegheny  County,  Pa 98 

Gore  pool,  Ohio 103 

Grant  County,  Ind 113 

Grass  Creek,  Wyo 144 

Hancock  County,  Ohio 112 

Healdton  district,  Oklahoma 133 

Humble  Field 168 

Himdred  foot  sand,  Pennsylvania 96 

Huntington  County,  Ind 113 

Irvine  pool,  Kentucky 106 

Jackson  Ridge  pool,  Ohio 102 

Johnson  pool,  Illinois 114 

Kern  River  field,  California 159 

Kirkwood  pool,  Illinois 115 

Lawrence  County,  III 115 

Lost  Hills  field,  California 156 

Lucas  County,  Ohio Ill 

Maricopa  Flat  area.  Sunset  oil  field,  California 152 

Marion  County,  111 113 

Marion  County,  Tex 139 

McDonough  County,  111 115 

Mclvittrick  field,  California 154 

Mercer  County,  Ohio 112 

Mooringsport  pool,  Louisiana 139 

Muskogee-Boynton  district,  Oklahoma 130 

Neodesha  district,  Kansas 122 

Nowata  district,  Oklahoma 124 

Okesa  district,  Oklahoma 125 

Okmulgee  district,  Oklahoma 131 

Olinda  field,  California . 166 

Pike  County,  Ind 116 

Pine  Island  pool,  Louisiana 140 

Plymouth  pool,  Illinois 115 

Ragland  pool,  Kentucky 104 

Red  River  field,  Louisiana 140 

Robinson  pool,  Illinois 114 

Salt  Creek  field,  first  Wall  Creek  sand,  A\'yoming 144 

Salt  Lake  field,  California 162 

Sandoval  pool,  Illinois 113 


INDEX  189 

PAQE 

Table — Continued. 

Estimated  future  production — Continued. 

Sandusky  County,  Ohio Ill 

Santa  Maria  field,  California 160 

Saratoga,  Rio  Bravo 170 

Seneca  County,  Ohio Ill 

Shinnston  pool,  West  Virginia 99 

Siggins  pool,  Illinois 114 

Sour  Lake 171 

Speechly  sand,  Pennsylvania 95 

St.  Marys  pool,  Ohio 102 

Sullivan  County,  Ind 116 

Twenty-five  Area,  California 151 

Upper  Lawrence  County,  111 115 

Van  Wert  County,  Ohio 102 

Ventura  County  field,  California 161 

Vinton 172 

Vivian  pool,  Louisiana 139 

Wayne  County,  Ky 106 

Wells  County,  Ind 112 

West  Coyote  field,  California 164 

Westfield  pool,  Illinois 113 

Whittier  field,  California 163 

Wood  County,  Ohio Ill 

Tampico-Tuxpam  region,  Mexico 173 

Tank  cars,  depreciation  of 72 

Tanks,  depreciation  of 69 

Tax  on  corporations  for  1918 4 

Taxes,  deductible 12 

Taxes,  not  deductible 13 

Tehuantepec-Tabasco  region,  Mexico 173 

Time  for  deduction  of  charges 11 

Tools,  depreciation  of 70 

Transportation  equipment,  depreciation  of 70 

Ultimate  production 87 

Underground  reserves  of  oil  recoverable,  estimate  of 80 

Unit  cost: 

Definition  of 28 

Determination  of • 28 

Natural  gas 32 

Upper  Lawrence  County,  111 115 

Valuation  of: 

Fee  under  lease 25 

Property,  schedule  for 53 

Valuation,  ruling  regarding 25 


190  INDEX 

PAQB 

Van  Wert  County,  Ohio 112 

Various  sands,  depletion,  apportionment  among 34 

Ventura  County  field,  California 160 

Vivian  pool,  Louisiana 139 

War-profits  and  excess-profits  tax 4 

Washington  County,  Ohio 102 

Washington  County,  Okla 122, 126 

Washington  County,  Pa 97 

Wayne  County,  Ky 105 

Wayne  County,  Ohio 103 

Well  equipment,  depreciation  of 68 

Wells  County,  Ind 112 

West  Coyote  field,  California 163 

Westfield  pool,  Illinois 113 

Wetzel  County,  W.  Va 101 

Whittier  field,  California 162 

Wood  County,  Ohio Ill 


my  2  5  1974 


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